El Paso Electric Company Integrated Resource Plan For the ......Paso Electric Company's (“EPE” or the “Company”) most recently filed periodic reports and in other filings made

El Paso Electric Company

Integrated Resource Plan For the Period 2018-2037

September 17, 2018

El Paso Electric Company 2018 Integrated Resource Plan

SAFE HARBOR STATEMENT This 2018 Integrated Resource Plan (“IRP” or alternatively, “Plan”) includes statements that are

forward-looking statements made pursuant to the safe harbor provisions of the Section 27A of

the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934,

as amended, including statements regarding load forecasts; statements regarding expected capital

expenditures; statements regarding generation facilities’ expected retirement dates; and

statements regarding the expected remaining useful life of resources. This information may

involve risks and uncertainties that could cause actual results to differ materially from such

forward-looking statements. Additional information concerning factors that could cause actual

results to differ materially from those expressed in forward-looking statements is contained in El

Paso Electric Company's (“EPE” or the “Company”) most recently filed periodic reports and in

other filings made by EPE with the U.S. Securities and Exchange Commission (the “SEC”), and

include, but is not limited to:

• Increased prices for fuel and purchased power and the possibility that regulators may not permit EPE to pass through all such increased costs to customers or to recover previously incurred fuel costs in rates

• Full and timely recovery of capital investments and operating costs through rates in Texas and New Mexico

• Uncertainties and instability in the general economy and the resulting impact on EPE’s sales and profitability

• Changes in customers’ demand for electricity as a result of energy efficiency initiatives and emerging competing services and technologies, including distributed generation

• Unanticipated increased costs associated with scheduled and unscheduled outages of generating plant

• Unanticipated maintenance, repair, or replacement costs for generation, transmission, or distribution facilities and the recovery of proceeds from insurance policies providing coverage for such costs

• The size of our construction program and our ability to complete construction on budget and on time

• Potential delays in our construction schedule due to legal challenges or other reasons

El Paso Electric Company 2018 Integrated Resource Plan

• Costs at Palo Verde Generating Station • Deregulation and competition in the electric utility industry • Possible increased costs of compliance with environmental or other laws, regulations and

policies • Uncertainties and instability in the financial markets and the resulting impact on EPE’s

ability to access the capital and credit markets • Actions by credit rating agencies • Possible physical or cyber-attacks, intrusions or other catastrophic events • Other factors of which we are currently unaware or deem immaterial

EPE’s filings are available from the SEC or may be obtained through EPE’s website,

http://www.epelectric.com. Any such forward-looking statement is qualified by reference to

these risks and factors. EPE cautions that these risks and factors are not exclusive. Management

cautions against putting undue reliance on forward-looking statements or projecting any future

results based on such statements or present or prior earnings levels. Forward-looking statements

speak only as of the date of this presentation, and EPE does not undertake to update any forward-

looking statement contained herein. The Company undertakes no obligation to update any

forward-looking statement or statements to reflect events or circumstances that occur after the

date on which such statement is made or to reflect the occurrence of unanticipated events, except

to the extent the events or circumstances constitute material changes in this IRP that are required

to be reported to the New Mexico Public Regulation Commission ("NMPRC" or "Commission")

pursuant to its IRP Rule, 17.7.3.10 New Mexico Administrative Code (“NMAC”).

El Paso Electric Company Page i 2018 Integrated Resource Plan

TABLE OF CONTENTS

I. EXECUTIVE SUMMARY ................................................................................................ 2 A. 2018 IRP Four-Year Action Plan:.............................................................................. 6

II. IRP PLANNING OVERVIEW........................................................................................... 7 A. Service Territory/Company Overview ..................................................................... 10 B. Summary of the 2015 IRP Action Plan and Status .................................................. 13

III. DESCRIPTION OF EXISTING RESOURCES ............................................................... 13 A. Supply Side Resources ............................................................................................. 13

1. Generating facilities and expected retirement dates ......................................... 14 2. Purchased Power Agreements .......................................................................... 18

B. Environmental Impacts of Existing Supply-Side Resources ................................... 19 1. Air Emissions ................................................................................................... 20 2. Climate Change ................................................................................................ 23 3. Modeling Carbon and Emissions Cost. ............................................................ 24 4. Water Resources ............................................................................................... 25 5. Biological resources ......................................................................................... 26 6. Cultural resources ............................................................................................. 26

C. Demand Side Resources .......................................................................................... 27 D. Storage Resources .................................................................................................... 35 E. Reliability Requirements ......................................................................................... 36 F. Existing Transmission Capabilities.......................................................................... 38 G. Back-Up Fuel Capabilities and Options .................................................................. 51

IV. CURRENT LOAD FORECAST ...................................................................................... 51 A. Forecast Summary ................................................................................................... 51 B. Load Forecast Methodology and Inputs .................................................................. 52 C. Weather Adjustment Detail...................................................................................... 56 D. Demand-Side Savings Detail ................................................................................... 57 E. Distributed Generation ............................................................................................. 57 F. Load Forecast Scenarios .......................................................................................... 59 G. Historical Forecast Accuracy and Comparison ........................................................ 61

V. LOAD AND RESOURCES TABLE ................................................................................ 64 VI. IDENTIFICATION OF RESOURCE OPTIONS (EXISTING CHARACTERISTICS

AND INTERACTIONS) .................................................................................................. 68 A. Supply Side Resources ............................................................................................. 68

1. Solar Photovoltaic Resource Options ............................................................... 69 2. Solar Coupled with Battery Storage ................................................................. 70 3. Wind Resource Options .................................................................................... 71 4. Biomass Resource Option ................................................................................ 72 5. Geothermal Resource Option ........................................................................... 72 6. Combined Cycle Resource Option ................................................................... 72 7. Combustion Turbine Resource Option ............................................................. 73 8. Gas Reciprocating Resource Options ............................................................... 73

B. Energy Storage ......................................................................................................... 74 C. Demand Side Resources .......................................................................................... 75

VII. DESCRIPTION OF THE RESOURCE AND FUEL DIVERSITY ................................. 86

El Paso Electric Company Page ii 2018 Integrated Resource Plan

VIII. IDENTIFICATION OF CRITICAL FACILITIES SUSCEPTIBLE TO SUPPLY-SOURCE OR OTHER FAILURES .................................................................................. 87

IX. DETERMINATION OF THE MOST COST EFFECTIVE RESOURCE PORTFOLIO AND ALTERNATIVE PORTFOLIOS ............................................................................. 88 A. Most cost effective portfolio (Base Case) ................................................................ 95 B. Considerations – Reliability ..................................................................................... 98 C. Alternative portfolios (sensitivities, carbon tax) ...................................................... 99 D. Recommended Portfolio ........................................................................................ 113

X. DESCRIPTION OF PUBLIC PROCESS ....................................................................... 115 XI. CONCLUSION ............................................................................................................... 130

El Paso Electric Company Page iii 2018 Integrated Resource Plan

LIST OF TABLES Table 1 – Most Cost Effective Portfolio ......................................................................................... 5 Table 2 – EPE Owned Existing Generation Stations and Fuel Types .......................................... 17 Table 3 – EPE Existing Renewable Generation Resources .......................................................... 18 Table 4 – Environmental Impacts of Existing Supply Side Resources ........................................ 21 Table 5 – Current Portfolio of New Mexico EE Programs and Program EUL ............................ 33 Table 6 – New Mexico Verified and Projected Participation, Impacts and Budget Portfolio ...... 34 Table 7 – Texas Verified and Projected Demand and Energy Savings ........................................ 35 Table 8 - Total Sales (MWh) Historical Forecast Accuracy ......................................................... 62 Table 9 - Native System Demand (MW) Historical Forecast Accuracy ...................................... 62 Table 10 - Annual Forecast Energy Sales Versus Peak Demand ................................................. 63 Table 11 - Initial L&R .................................................................................................................. 65 Table 12 – IRP Resource Options Input Assumptions ................................................................. 77 Table 13 – Storage Resource Option Input Assumptions ............................................................. 78 Table 14 – IRP Resource Options Input Assumptions ................................................................. 79 Table 15 - Rate Structure Development........................................................................................ 85 Table 16 - Base Case Portfolio ..................................................................................................... 96 Table 17 - Base Case Portfolio Nameplate Mix ........................................................................... 97 Table 18 - Low Load Sensitivity ................................................................................................ 102 Table 19 - High Load Sensitivity ................................................................................................ 103 Table 20 - Low Fuel Cost Sensitivity ......................................................................................... 105 Table 21 - High Fuel Cost Sensitivity......................................................................................... 106 Table 22 - $8 Carbon Tax Sensitivity ......................................................................................... 108 Table 23 - $20 Carbon Tax Sensitivity ....................................................................................... 109 Table 24 - $40 Carbon Tax Sensitivity ....................................................................................... 110 Table 25 – No Combined Cycle Sensitivity ............................................................................... 112 Table 26 - L&R Most Cost Effective Portfolio .......................................................................... 114

El Paso Electric Company Page iv 2018 Integrated Resource Plan

LIST OF FIGURES

Figure 1 EPE Service Territory ..................................................................................................... 12 Figure 2 - EPE Transmission Rights and Ownership ................................................................... 41 Figure 3 - Native System Energy Forecast Scenario Comparison ................................................ 60 Figure 4 - Native System Peak Demand Forecast Scenario Comparison ..................................... 60 Figure 5 - EPE 2017 Energy Fuel Mix ......................................................................................... 87 Figure 6 - Duck Curve at Various Solar Integration Levels ......................................................... 91 Figure 7 - Monthly Wind Profiles ................................................................................................. 94

El Paso Electric Company Page 1 2018 Integrated Resource Plan

LIST OF ATTACHMENTS

Attachment A-1: Original Public Advisory Meeting Schedule ................................................. 131 Attachment A-2: Final Public Advisory Meeting Schedule ...................................................... 132 Attachment A-3: Public Advisory Schedule with IRP Rule Requirements ............................... 133 Attachment A-4: Feedback Forms Summary ............................................................................ 134 Attachment A-5: Resource Input Template Example ................................................................ 139 Attachment A-6: Existing Units Operating Characteristics ....................................................... 139

Attachment B-1: 2018 Long Term Forecast ............................................................................... 153 Attachment C-1: Transmission Facilities.................................................................................... 155 Attachment D-1: Lazard’s........................................................................................................... 164 Attachment E-1 : Expansion Plan Results – Base Case and Sensitivities ................................ 165


I. EXECUTIVE SUMMARY

EPE presents this Plan pursuant to the requirements of the Commission’s IRP Rule, 17.7.3

NMAC (“IRP Rule”) and in accordance with the Joint Stipulation in Case No. 15-00241-UT

(“Stipulation Agreement”) from EPE’s 2015 IRP. This document discusses EPE’s integrated

resource planning process (the “Planning Process”) and develops an integrated resource portfolio

to safely, reliably and cost-effectively meet the energy needs of EPE’s customers for the next

twenty years. The IRP public advisory process (the “Public Process”), as set forth in the IRP

Rule, was initiated with the first public advisory group (collectively the public advisory group,

members of the public, and public participants in the IRP Process will be referred to herein is as

either the “PAG” or “Participants”) meeting on May 25, 2017, approximately sixteen months

prior to the extended filing date of September 17, 2018. EPE is committed to and supportive of

the PAG’s efforts, which resulted in a total of 17 meetings, 14 pre-scheduled by EPE, and three

additional meetings at the request of the PAG. The Participants were active in the Planning

Process with questions and suggestions for consideration in the IRP. The Plan identifies the

public input which has been incorporated into the IRP analysis within their respective topics.

EPE is located on the southeastern edge of the Western Electric Coordinating Council ("WECC")

and is interconnected by three major transmission tie lines. EPE’s current supply-side resource

mix includes 633 Megawatts (“MW”) from the Palo Verde Nuclear Generating Station

(“PVNGS”) outside Phoenix, Arizona, 1,446 MW of gas-fired local generation inside EPE’s

service territory, and 115 MW of solar generation, also located within EPE’s service territory.

EPE’s IRP analysis included consideration for the planned retirement of six units within the 20-


year planning horizon (the “Planning Horizon”), a total of 578 MW of summer net capacity

planned for retirement. The IRP evaluates how to address these planned retirements safely,

reliably, and most cost effectively along with EPE’s forecasted load growth in order to develop

an optimal portfolio. As defined in the Stipulation Agreement, any planned retirements within

the first five years of the Planning Horizon1 were to be analyzed within the capacity expansion

model to determine if these units’ retirement dates could be extended safely, reliably, and

economically. The retirement extensions were not selected in the Planning Process base case.

The Public Process included, in part, a review of the forecasted energy needs, EPE’s

transmission system, reliability requirements, environmental impacts, rate considerations, and

existing energy resources. In consideration of all resource options, EPE incorporated the

requirements of New Mexico’s Renewable Energy Act ("REA"), New Mexico Statutes

Annotated 1978 (“NMSA”) § 62-1-16 et seq. and Efficient Use of Energy Act NMSA 1978 § 62-

1-17 et seq. ("EUEA") into the Planning Process. The renewable energy and energy efficiency

resource options considered were above and beyond the REA and EUEA requirements. The

identification of energy resource options included a mix of energy efficiency, demand-side

management, renewable energy, battery storage, and traditional supply-side generating

resources.

The Loads and Resources Table ("L&R") includes REA resources and future EUEA growth

amounts. The L&R is shown in Table 25. The L&R format has been updated from EPE’s

previous 2015 IRP to more easily distinguish resource additions and separately identify battery

storage. 1 Per Final Order in Case No. 17-00317-UT, this will include Rio Grande Unit 6.


The resulting resource portfolio additions include a mix of solar, battery storage, and

conventional gas generation. The identified resource additions result in the optimal cost

effective resource portfolio. The battery storage and conventional gas generation resources

compliment the solar resources, which are intermittent in nature. The table below lists the

resource additions by year as selected by the Planning Process. It is noted that the actual

resource additions in the future will be determined by results of competitive requests for

proposals and may differ based on future changes to forecasted loads, economic conditions,

technological advances, and environmental and regulatory standards.


Table 1 – Most Cost Effective Portfolio

Year Resource Capacity Contribution to Peak

2018 2019 2020 2021

Solar PV 25 6.25

2022

Solar PV 75 18.75 Solar PV 75 18.75 Solar PV 75 18.75 Solar PV 100 25 Battery Storage 15 15

2023 Combined-Cycle 320 320 2024 2025 2026

2027

Solar PV 100 25 Combustion Turbine 100 100 Reciprocating Engine 100 100 Battery Storage 50 50

2028 Combustion Turbine 100 100 2029 2030 2031 Combined-Cycle 320 320 2032 2033

2034 Combustion Turbine 100 100 Reciprocating Engine 100 100

2035 Battery Storage 50 50

2036 Solar PV & Battery 100 0 30 30

2037 Biofuel 20 20


A. 2018 IRP Four-Year Action Plan:

As required in the IRP Rule, EPE’s four-year action plan includes the following:

• Finalize selection of the 2017 RFP and EPE will complete the regulatory process for the

selected RFP winning proposals. These regulatory processes may include approval of

Certificate of Convenience and Necessity (“CCN”) or Long-Term Purchased Power

Agreement (“LTPPA”) dependent on selected resources.

• EPE will complete the regulatory approval process for the 2018 Annual Renewable

Energy Plan filed May 1, 2018 and will file subsequent annual reports and plans in 2019,

2020, 2021, and 2022 pursuant to 17.9.572 NMAC and the REA.

• EPE will complete the regulatory approval process for the 2019-2021 Energy Efficiency

and Load Management Plan filed July 1, 2018, and will file a subsequent 3-year plan

pursuant to 17.7.2 NMAC and the EUEA.

• Evaluate Demand Response Pilot Program (“DRPP”) results at the conclusion of the

three year pilot program or earlier if possible. Based on those results, EPE will determine

appropriate course of action.

• EPE will issue RFP(s) in 2021 or 2022 to address the resource need identified in 2027.

The exact date for the RFP will be determined based on a continued evaluation of future

changes to forecasted loads, economic conditions, technological advances, and

environmental and regulatory standards.

• Consider voluntary customer programs for renewable energy.


II. IRP PLANNING OVERVIEW

The Plan was developed pursuant to the requirements of the IRP Rule. The Planning Process

took into consideration the following key objectives:

• identifying the most cost effective portfolio of resources;

• considering various resource options, including supply-side and demand-side options, while

taking into consideration environmental impacts, reliability, and risk; and

• conducting the Public Process to provide information to and receive and consider inputs from

the public regarding the Planning Process.

The Planning Process can be described as the method to develop the most cost effective

integrated resource portfolio in order to supply safe, reliable, and environmentally conscientious

energy to meet the needs of EPE’s customers for the next twenty years. The purpose of the IRP

Rule is:

"…to identify the most cost effective portfolio of resources to supply the

energy needs of customers. For resources whose costs and service

quality are equivalent, the utility should prefer resources that minimize

environmental impacts."


Section 10 of the EUEA calls for the periodic filing of an IRP with the Commission. The IRP

Rule requires that the following information be included in an electric utility's IRP:

• a description of existing electric supply-side and demand-side resources,

• a current load forecast as described in this Rule,

• a load and resources table,

• the identification of resource options,

• a description of the resource and fuel diversity,

• the identification of critical facilities susceptible to supply-source or other failures,

• the determination of the most cost effective resource portfolio and alternative portfolios,

• a description of the Public Process,

• an action plan, and

• other information that the utility finds may aid the Commission in reviewing the utility's

planning processes.

Statutory energy efficiency goals and renewable energy standards are incorporated into the

Planning Process. EPE evaluated renewable and energy efficiency resources well and above the

REA and EUEA requirements through the Planning Process. For example, the EUEA

establishes energy efficiency goals, and energy efficiency programs are approved by the

Commission. EPE met its 2020 statutory Energy Efficiency goal several years ago, in 2016. In

addition, the REA establishes a Renewable Portfolio Standard (“RPS”) for EPE's New Mexico

jurisdiction, requiring an amount of renewable resources based on a percentage of EPE's annual

New Mexico retail energy sales, and contains additional diversity requirements. Utilities are not


required to add additional REA resources when costs exceed a reasonable cost threshold

("RCT"). EPE’s RPS portfolio is currently above the RCT, and EPE has requested and received

approval for variances and waivers from further REA procurements through 2019. EPE is in

compliance with the REA.

EPE committed a significant amount of time and resources to the Public Process. The Public

Process allowed EPE to receive valuable feedback and insight into what different members of the

community value in EPE’s Planning Process. While the Public Process is required by the IRP

Rule, EPE supports the integral role it plays in the IRP.

While the IRP requirement is a three year cycle, an electric utility company continually evaluates

its resource plan. The ongoing Planning Process can be summarized as:

• utilizing the latest load forecast that incorporates data for distributed generation and energy

efficiency, and comparing that to the most current information for existing supply-side

resources and their expected retirement dates to determine a baseline for future capacity

needs,

• if a capacity need is identified, establishing possible demand-side and supply-side resources

that may be utilized to serve load safely and reliably. This also requires the consideration of

advancements in technology and resource options including the complexities of resource

characteristics and costs. The incorporation of data from the prior IRP results, along with

publicly available information, to form resource assumptions,


• analyzing resource options to ensure reliability, adequacy and appropriate integration into

EPE’s system. Select the most cost-effective portfolio of resources to meet EPE’s peak load

and operational system needs, safely and reliably,

• the incorporation of all applicable forecast data, existing resource information and expansion

portfolio into the L&R, and

• annual updates with latest forecast and resource data.

EPE follows the process as summarized above during its annual and continuous resource

planning course of business. However, during years where the Planning Process is occurring,

there are several key additions:

• performance of sensitivity analyses of various factors, such as load forecast, fuel cost and

carbon tax considerations at various rates, along with feasible supply side and demand side

resource options as suggested by the PAG, and

• production of the four-year action plan.

A. Service Territory/Company Overview

EPE is a public utility engaged in the generation, transmission and distribution of

electricity in an area of approximately 10,000 square miles in west Texas, and southern

New Mexico (from Van Horn, Texas to Hatch, New Mexico). The Company serves

approximately 417,900 residential, commercial, industrial, public authority and wholesale


customers. The Company distributes electricity to retail customers principally in El Paso,

Texas, and Las Cruces, New Mexico (representing approximately 64% and 11%,

respectively, of the Company’s retail revenues for the year ended December 31, 2017). In

addition, the Company’s wholesale energy sales include those for resale to other electric

utilities and to power marketers. Principal industrial, public authority and other large retail

customers of the Company include United States military installations, such as Fort Bliss in

Texas, as well as White Sands Missile Range ("White Sands") and Holloman Air Force

Base ("HAFB"), both in New Mexico. EPE also serves an oil refinery, several medical

centers, two large universities and a steel production facility. Figure 1 shows a

geographical representation of EPE’s total service territory.


Figure 1 EPE Service Territory


B. Summary of the 2015 IRP Action Plan and Status

EPE has completed all required items set forth in its 2015 IRP four-year action plan. In

July, 2016, EPE sold its interests in the Four Corners Power Plant (“FCPP”). EPE filed and

received approval of its 2015, 2016, and 2017 RPS pursuant to 17.9.572 NMAC and the

REA. EPE filed and obtained approval of its Energy Efficiency programs in 2016 pursuant

to 17.7.2 NMAC and the EUEA. EPE received approval for its Demand Response Pilot

Program (“DRPP”), which is in its first year of operation, and explained in more detail

below. Finally, in 2017, EPE issued an all-source request for proposals (“RFP”).

III. DESCRIPTION OF EXISTING RESOURCES

A. Supply Side Resources

EPE’s existing supply side resources provide a foundation for integrated resource planning.

EPE utilizes its current supply side resources to satisfy the bulk of its customers' electrical

demands with power generated from Company owned generating stations fueled by solar,

natural gas, and uranium. EPE also purchases renewable energy through various long-term

Purchased Power Agreements ("PPAs"). In addition, EPE purchases varying amounts of

firm and non-firm energy through the wholesale markets to meet the needs of its customers.

These resources, in combination with future low-cost, efficient options will create a


portfolio that, taking into consideration reliability and risk, result in the most cost-effective

plan.

1. Generating facilities and expected retirement dates

EPE owns and operates a fleet of local and remote generating units. The Rio Grande

Generating Station ("Rio Grande"), Newman Generating Station ("Newman"),

Montana Power Station ("MPS"), and Copper Generating Station ("Copper") are all

located in EPE's service territory, within or near the City of El Paso, Texas. These

generating stations are considered EPE's local generation. In addition, EPE owns six

small solar photovoltaic ("PV") systems located at (1) Rio Grande in Sunland Park,

New Mexico, (2) Newman in northeast El Paso, (3) Wrangler Substation in east

El Paso, (4) the El Paso Community College – Valle Verde Campus in El Paso's

Lower Valley, (5) EPE’s Van Horn customer service center, and (6) the rooftop of

EPE's headquarters in downtown El Paso.

EPE recently expanded its renewable portfolio with the addition of two new solar

resources. The Texas Community Solar program is a 3 MW Solar PV system located

on approximately 21 acres near MPS. The Texas Community Solar program allows

customers to voluntarily subscribe to utility scale single-axis tracking PV based on

their current usage. This solar project became commercially operational May 31,

2017. On March 20, 2018, EPE filed with the Public Utility Commission of Texas


(“PUCT”) to expand the Texas Community Solar program by 2 MW, utilizing 2 MW

of solar from the 10 MW Newman Solar Facility.

The Holloman Solar Facility is currently under construction. This project will

provide an additional 5 MW of capacity to serve HAFB. The facility is an EPE-

owned solar resource dedicated to serve HAFB and is expected to become

commercially operational by the third quarter of 2018.

On April 24, 2018, EPE filed with the Commission an Application for Approval of a

New Mexico Community Solar program. If approved, EPE will build and maintain a

2 MW solar facility located just south of Las Cruces, New Mexico.

PVNGS, located near Phoenix, Arizona, is considered EPE's remote generation. EPE

owns 15.8 percent of the PVNGS' Units 1, 2, and 3.

EPE's existing generating stations and fuel types are listed in Table 2 below, together

with in-service and currently planned retirement dates. Table 2 includes Rio Grande

Unit 6 as required in the Final Order of Case No. 17-00317-UT. As is evident from

Table 2, the majority of EPE's generating facilities have been in service for a

significant number of years. This is an important consideration for integrated

resources planning because aging units being considered for retirement within the

Planning Horizon will affect EPE’s capacity needs. Additional output data required


by the IRP Rule, such as capacity factor, fuel costs, heat rate, and total Operation and

Maintenance (“O&M”), is provided hereto in Attachment B-1


Table 2 – EPE Owned Existing Generation Stations and Fuel Types

Generating Station Location

Nominal Capacity

(MW) Primary

Fuel Type Secondary Fuel Type

In-Service Date

Planned Retirement

Date

Unit Age at

Planned Retirement

PVNGS Unit 1 Unit 2 Unit 3

Phoenix, AZ 633 Uranium N/A February 1986 September1986 January 1988

June 2045 April 2046 November 2047

59 60 59

Montana Unit 1 Unit 2 Unit 3 Unit 4

El Paso, TX 354 Natural Gas Fuel Oil

March 2015 March 2015 May 2016 September 2016

December 2055 December 2055 December 2056 December 2056

40 40 40 40

Rio Grande Unit 6 Unit 7 Unit 8 Unit 9

Sunland Park, NM 321 Natural Gas N/A

June 1957 June 1958 July 1972 May 2013

December 2018 December 2022 December 2033 December 2058

61 64 61 45

Newman Unit 1 Unit 2 Unit 3 Unit 4 Unit 5 – CTs Unit 5 – HRSG

El Paso, TX 752 Natural Gas Fuel Oil Units 1-3

May 1960 June 1963 March 1966 June 1975 May 2009 April 2011

December 2022 December 2022 December 2026 December 2026 December 2050 December 2050

62 59 60 51 41 39

Copper Unit 1 El Paso, TX 64 Natural Gas N/A July 1980 December 2030 50

EPE Owned Solar Community Solar Holloman Solar Small Solar Systems

EPE Service Territory

3 5

<1 N/A N/A

May 2017 Q3 2018 2009 – 2011

May 2047 Q3 2048 2029 – 2032

Various


2. Purchased Power Agreements

In addition to relying on its own generating facilities, EPE also relies on resources

acquired from wholesale suppliers or other sources. The current long term PPAs that

EPE has in place to serve its customers are listed in Table 3 below:

Table 3 – EPE Existing Renewable Generation Resources

Purchase Power Agreement Location

Nominal

Capacity

(MW)

In-Service

Date Term

NRG Solar Roadrunner LLC (“NRG”)

Santa Teresa, NM 20 August 2011 20 years

Southwest Environmental Center (“SWEC”)

Las Cruces, NM .006 April 2008 20 years

Hatch Solar Energy Center I, LLC (“Hatch”)

Hatch, NM 5 July 2011 25 years

SunE EPE1, LLC (“SunEdison”)

Chaparral, NM 10 June 2012 25 years

SunE EPE2, LLC (“SunEdison”)

Las Cruces, NM 12 May 2012 25 years

Macho Springs Solar, LLC (“Macho Springs”)

Luna County, NM 50 May 2014 20 years

Newman Solar LLC (“Newman”)

El Paso, TX 10 December 2014 30 years

Additionally, interconnected to EPE’s system is a biogas energy qualifying facility

("QF"), Camino Real Landfill Gas to Energy Facility (3.2 MW) located in Sunland

Park, New Mexico (at the Camino Real Landfill). Further, EPE offers QF net

metering and renewable energy certificate (“REC”) programs for customer-owned

solar PV and wind generation. The resulting customer-generated energy is used first

to supply that customer's needs, then, if excess energy is produced, it is delivered to


EPE's system. The RECs obtained through these resources, if located in New

Mexico, are used to meet EPE’s New Mexico RPS requirements.

In combination with existing EPE owned resources, these PPAs provide diverse

capacity to serve load and give EPE and its customers a robust starting point when

analyzing the most cost-effective integrated resource plan.

Additionally, EPE has utilized short-term market purchases in order to mitigate the

need for new resource additions and to allow for economic resource selections. The

firm energy purchase transactions are defined by the Western Systems Power Pool

Agreement (“WSPP”) Service Schedule C, the service schedule associated with firm

energy. However, over the long term, EPE is responsible for securing resources to

meet future load requirements. The designation of energy as firm under Schedule C

states the interruption of a power transaction cannot be for economic purposes, and is

allowable under a limited number of circumstances including the sellers need to

reliably serve its native load customers. Each Balancing Authority is responsible for

securing adequate resources to serve load.

B. Environmental Impacts of Existing Supply-Side Resources

EPE has a firm commitment to environmental stewardship and consistently evaluates

potential impacts to environmental resources during resource planning processes. In

general, the environmental considerations for siting renewable generation facilities,


conventional generation facilities, and transmission and distribution facilities are similar,

though the resources impacted vary greatly based on the type, location, geographic setting,

and expanse of any given project. The degree of environmental regulatory guidance and

review will also vary based on the location and other project specific parameters; but, in all

cases environmental resources are considered.

EPE is subject to extensive laws, regulations and permit requirements with respect to air

and greenhouse gas ("GHG") emissions, water discharges, soil and water quality, waste

management and disposal, natural resources and other environmental matters by federal,

state, regional, tribal, and local authorities.

1. Air Emissions

Emission rates for each of EPE’s generation facilities required by 17.7.3.9(C)(13)(b)

NMAC are listed in Table 4 below. The Clean Air Act ("CAA"), associated

regulations and comparable state and local laws and regulations that relate to air

emissions impose, among other obligations, limitations on pollutants generated

during the operations of the Company's facilities and assets, including sulfur dioxide

("SO2"), particulate matter ("PM"), nitrogen oxides ("NOx") and mercury.


Table 4 – Environmental Impacts of Existing Supply Side Resources

Impacts to air quality are evaluated against CAA regulations to determine suitability

of a proposed technology and feasibility of permitting. During the permitting phase

of a project with potential emissions, ranging from the purchase of an emergency

generator to installation of a new conventional generation unit, an emissions review is

conducted. During this review, potential emission constituents and rates are

evaluated to determine potential impacts and what, if any, emission thresholds are

triggered. Technologies and pollution control methods are selected to meet or exceed

the requirements set forth by State and Federal regulations, including the National

NOx1 CO23 CO1 PM Hg SO22 Water Consumption4, 5

(lbs/kWh) (lbs/kWh) (lbs/kWh) (lbs/kWh) (lbs/kWh) (lbs/kWh) (gal/kWh-site)Montana 1 0.00012 1.05 0.00004 0.00006 * 0.00001Montana 2 0.00012 1.05 0.00005 0.00006 * 0.00001Montana 3 0.00015 1.11 0.00003 0.00007 * 0.00001Montana 4 0.00011 1.04 0.00003 0.00006 * 0.00001Rio Grande 6 0.00218 1.50 0.00031 0.00002 * 0.00001Rio Grande 7 0.00156 1.36 0.00003 0.00001 * 0.00001Rio Grande 8 0.00231 1.32 0.00012 0.00008 * 0.00001Rio Grande 9 0.00013 1.09 0.00005 0.00001 * 0.00001Newman 1 0.00216 1.41 0.00024 0.00001 * 0.00001Newman 2 0.00197 1.39 0.00099 0.00001 * 0.00001Newman 3 0.00253 1.29 0.00000 0.00001 * 0.00001Newman 4** 0.00139 1.10 0.00021 0.00001 * 0.00001Newman 5*** 0.00287 1.23 0.00006 0.00008 * 0.00001Copper 1 0.00486 2.05 0.00145 0.00011 * 0.000002 0.10Palo Verde 1 0 0 0 0 0 0Palo Verde 2 0 0 0 0 0 0Palo Verde 3 0 0 0 0 0 0

*No oil burned in 2017; therefore, no Hg emissions were created. ** Newman GT-1 and GT-2*** Newman SC and CC 6A and 6B1. Rio Grande, Newman, & Copper NOx & CO emission data from continuous emissions monitoring system.2. Rio Grande, Newman, & Copper SO2 emission data calculated from natural gas fuel sulfur content.3. Rio Grande & Newman CO2 emission data calculated as per 40 CFR 75 Appendix G Equation G-4; Copper as per 40 CFR 98 Subpart C.4. Rio Grande & Newman water consumption data calculated based on maximum cooling tower rate and 2017 unit capacity factor.

5. El Paso Electric's water consumption at Palo Verde is estimated as 15.8 percent (EPE's owbership) of water consumed by Units 1, 2, and 3.

0.73

2017 Data: Based on Rolling Average

Unit

0.20

0.74

0.59


Ambient Air Quality Standards ("NAAQS"). Most of EPE’s air emissions result

from the combustion of fossil fuels. Consequently, conventional generation projects

undergo the most rigorous air quality assessments. However, air quality is considered

in the full scope of projects including fugitive dust during construction and large area

land clearing, as well as operations and maintenance traffic volume along

transmission rights-of-way.

Under the CAA, the Environmental Protection Agency (“EPA”) sets NAAQS for six

criteria pollutants considered harmful to public health and the environment, including

PM, NOx, carbon monoxide ("CO"), ozone and SO2. NAAQS must be reviewed by

the EPA at five-year intervals. On October 1, 2015, the EPA released a final rule

tightening the primary and secondary NAAQS for ground-level ozone from its 2008

standard levels of 75 parts per billion (ppb) to 70 ppb. Ozone is the main component

of smog. While not directly emitted into the air, it forms from precursors, including

NOx and volatile organic compounds, in combination with sunlight. The EPA may

designate the areas in which we operate as nonattainment. Specifically, in December

2017, EPA proposed to designate southern Dona Ana County, New Mexico, as a

nonattainment area. In June of 2018 the EPA provided public notice of this

designation. States that contain any areas designated as nonattainment will be

required to complete development of State Implementation Plans in the 2020-2021

timeframe.


Nonattainment areas are expected to have until 2020 or 2023 to meet the primary

(health) standard, with the exact attainment dates varying based on the ozone level in

the area. The Company continues to evaluate the impact these final and proposed

NAAQS could have on operations.

2. Climate Change

There has been a wide-ranging policy debate, at the local, state, national, and

international levels, regarding GHGs and possible means for their regulation. Efforts

continue to be made in the international community toward the adoption of

international treaties or protocols that would address global climate change issues. In

April 2016, the United States signed the Paris Agreement, which requires countries to

review and "represent a progression" in their intended nationally determined

contributions, and sets GHG emission reduction goals every five years, beginning in

2020. In August 2017, the United States formally documented to the United Nations

its intent to withdraw from the Paris Agreement. The earliest possible effective

withdrawal date from the Paris Agreement is November 2020.

The federal government has either considered, proposed and/or finalized legislation

or regulations limiting GHG emissions, including carbon dioxide ("CO2"). In

particular, the U.S. Congress has considered legislation to restrict or regulate GHG

emissions. In October 2015, the EPA published a rule establishing guidelines for


states to regulate CO2 emissions from existing power plants, known as the Clean

Power Plan ("CPP"). Legal challenges to the CPP are ongoing.

While it is not possible to predict the precise outcome of any pending, proposed or

future GHG legislation by Congress, state or multi-state regions or any GHG

regulations adopted by the EPA or state agencies, a significant portion of EPE’s

generation assets are nuclear or gas-fired. As a result, the Company’s GHG

emissions are low relative to electric power companies who rely more on coal-fired

generation, and largely align with proposed GHG regulations.

Climate change also has potential physical effects relevant to the Company's

business. In particular, climate change could affect the Company's service area by

causing higher temperatures, less winter precipitation and less spring runoff, as well

as by causing more extreme weather events. Such developments could change the

demand for power in the region and could also impact the price or ready availability

of water supplies or affect maintenance needs and the reliability of Company

equipment.

3. Modeling Carbon and Emissions Cost.

As discussed, the details of future carbon regulations remain in flux; however, EPE

anticipates that carbon regulations will ultimately become formalized at the state

and/or federal level. The physical consequences of climate change as well as the


regulatory approach to climate change ultimately selected and implemented by

governmental authorities, or both, may impact EPE’s operation. As such, EPE

models the Commission’s standardized cost (per ton) of CO2 emissions, as well as a

cost for criteria pollutants, within each resource portfolio. EPE’s modeling includes

emission rates specific to each conventional resource type and applicable costs as part

of the portfolio analysis.

4. Water Resources

Rate of consumptive water use, required by 17.7.3.9(C)(13)(c) NMAC, is

summarized for EPE’s existing generation resources in Table 4, and is a primary

consideration in comparing generation technologies and evaluating resource

portfolios. Protection and preservation of water resources is primarily governed by

the Clean Water Act. Assessment of potential impacts to water resources includes

surface water, ground water, wetlands, and other waters of the United States. Water

quality standards must be maintained throughout the life of a project from

construction through operation. These standards generally are addressed through

design factors to prevent storm water pollution and prevent site run-off and discharge.

Protection of wetlands and surface waters, including potentially dry arroyos, is best

addressed through site selection and any impacts to wetlands or waters of the U.S. are

mitigated during appropriate permitting processes.


5. Biological resources

Biological resources include wildlife, avian, vegetation and habitat resources.

Regulation of these resources is driven primarily by the Endangered Species and

Migratory Bird Treaty Acts. Procedurally, consideration of these resources requires

reconnaissance and detailed surveys of potential project areas to evaluate for the

presence of native, rare, or critical habitat; or threatened, endangered or other special

status species. Protection of biological resources is most challenging for expansive or

large land area projects such as solar facilities, transmission corridors or access roads.

EPE seeks to minimize impacts to these resources through careful site selection and

avoidance as well as through operational techniques such as timing of vegetation

clearing when seasonally appropriate to minimize impacts to nesting birds or

conducting salvage removal of cacti species or nest relocations when avoidance is not

possible.

6. Cultural resources

Cultural resources are abundant and dense within EPE’s service territory. Evaluation

of potential impacts to cultural resources follows the process outlined by Section 106

of the National Historic Preservation Act and includes a determination of whether or

not cultural resources exist within a project’s area of potential effect and whether or

not those resources would be adversely affected. These determinations are made in

consultation with the State Historic Preservation Office and any appropriate pueblos


and tribes, generally upon completion of intensive surveys and records reviews.

Where cultural resources cannot be avoided, mitigation plans are developed prior to

any construction. As with biological resources, managing the effects to cultural

resources is best achieved through careful site selection and avoidance. However, on

expansive projects complete avoidance is not always feasible and mitigation,

including site specific data recovery, is completed.

Although no less important, the following resources are also protected or otherwise

regulated and considered, though are not as frequently applicable to projects. These

include: environmental justice, protection of specially designated areas, visual

resources, paleontological resources, caves and karst, floodplains, watershed,

hazardous and solid wastes, and soils.

EPE evaluates potential impacts to a broad spectrum of environmental resources. The

resources and degree of impacts do vary from project to project, but the due

consideration of that impact is a consistent factor in EPE’s resource planning process.

C. Demand Side Resources

As referenced in Section V of this Plan, demand side resources are included in Section

4.0 of the L&R and are a reduction to the overall forecasted native system demand.

EPE’s existing demand side resources are categorized into three primary types as follows:


1. DRPP (New Mexico and Texas)

2. New Mexico Energy Efficiency Programs

3. Texas Energy Efficiency Programs

EPE incorporates demand side resources into its planning process for its New Mexico and

Texas jurisdictions. EPE has several programs that promote energy and demand savings

for customers. The programs differ by state jurisdiction and are dependent on the goals

established by state regulations.

Brief descriptions of the DRPP, the New Mexico Energy Efficiency ("EE") programs and

Texas EE portfolio are included below. EPE will continue to consider demand side

resource options as part of its IRP as described in Section VI.

1. DRPP

The Commission’s Final Order in Case No 17-00016-UT approved EPE’s DRPP.

Pursuant to that order, EPE implemented its Rate No. 37 - eSmart Thermostat

Program. EPE’s DRPP (otherwise known as the "eSmart Thermostat Program")

engages utility customers to reduce their electricity use (load) during peak hours or

under certain conditions using "smart thermostat" technology. Peak electricity

demand typically occurs on hot summer days when households turn on their air

conditioning (“A/C”). The primary goal of the DRPP is customer reduction of A/C

usage on hot summer days, which in turn, can substantially reduce demand for


electricity during EPE’s peak hours, providing aggregate benefits for the electric

grid and households themselves.

This pilot program was limited to 3,000 devices. This cap was reached on

November 17, 2017, and the program was closed for new enrollments. Eighty-one

percent (81%) of accepted customers were from Texas and nineteen percent (19%)

were from New Mexico.

The demand response season begins on June 1 and continues through September 30

each year. During the 2017 season, EPE executed 12 demand response events.

Each event lasted a maximum four hours in duration and was executed between

2:00 PM at 8:00 PM Mountain Daylight Time on non-holiday weekdays. EPE

tested several load control strategies to determine the DRPP’s effectiveness under

various conditions. Some of the strategies included temperature offsets of 2 to 4

degrees, different event durations, and pre-cool.

2. New Mexico Energy Efficiency Programs

In New Mexico, the EUEA and the Energy Efficiency Rule, 17.7.2 NMAC (“EE

Rule”) requires utilities to include cost effective EE and load management programs

in their resource portfolios. The EUEA requires EPE to attain a minimum

cumulative energy savings goal of eight percent of its 2005 New Mexico

jurisdictional retail sales from 2008 through 2020, 105,304,953 kWh. EPE began


its CFL Lighting Program and its LivingWise® educational program in late 2008.

EPE formally implemented the remainder of its initial New Mexico programs in

January 2009. In utilizing Commission-approved portfolios of demand side

resources, EPE achieved a cumulative savings of 118,301,310 kWh from 2008

through 2017, which is 112.34% of EPE’s 2020 New Mexico statutory goal.

In Case No. 16-00185-UT, EPE received Commission approval to offer its current

portfolio of EE and load management programs for its New Mexico retail customers

for the 2017 plan year. Pursuant to the EE Rule, EPE continues to offer these

programs.

EPE currently offers five residential programs and two commercial programs that

have been approved by the Commission. Below is a brief description of EPE's

current New Mexico EE programs:

• The Residential Comprehensive Program offers rebates for the installation of

ceiling and floor insulation, duct sealing, air infiltration, evaporative coolers,

refrigerated A/C units, solar screens and pool pumps.

• The New Mexico EnergySaver (Low Income) Program provides income-

qualified customers a variety of EE measures for their homes at no cost.

Qualification is based on an annual household income at or below 200% of the

federal poverty guidelines.


• The LivingWise® Program is an educational program for students. Participating

teachers are provided with educational materials that are presented in the

classroom.

• The CFL & LED Program offers discounts at participating retail locations for

customers to replace their existing light bulbs with more energy efficient light

bulbs.

• The ENERGY STAR® New Homes Program provides incentives for

homebuilders to construct energy efficient homes that exceed the current

building code.

• The Small Commercial Comprehensive Program provides small commercial

customers incentives for lighting, lighting controls, HVAC upgrades, HVAC

controls, HVAC tune-ups, cool roofs, vending miser controls, and solar

screen/film window treatments.

• The SCORE Plus Program provides incentives to large commercial customers,

as well as schools, city and county customers for EE measures including

lighting, lighting controls, HVAC upgrades, HVAC controls and custom

projects.

Table 5 below provides EPE's New Mexico EE Portfolio of Programs and their

Average Estimated Useful Life (“EUL”).



Table 5 – Current Portfolio of New Mexico EE Programs and Program EUL

PROGRAM ESTIMATED USEFUL

LIFE1

Residential Programs

LivingWise® 9

Residential Comprehensive 15

CFL & LED 12

ENERGY STAR® New Homes 21

EnergySaver (Low Income) 16

Commercial Programs

SCORE Plus 14

Small Commercial Comprehensive 14

1. EUL values as identified by the statewide Measurement and Verification Evaluator for program year 2017.

Table 6 provides the actual verified savings for EPE's New Mexico EE programs

for 2015 to 2017 and provides anticipated savings for 2018 to 2021. The 2018

projected savings are based on EPE’s 2017 Plan approved by Final Order in

NMPRC Case No. 16-00185-UT. The 2019 to 2021 projected savings are as

originally filed in NMPRC Case No. 18-00116-UT. The gross MW and Megawatt-

hour (“MWh”) projections do not include a peak demand coincidence factor

adjustment that is used for load forecasting purposes reflected in the L&R.


Table 6 – New Mexico Verified and Projected Participation, Impacts and Budget Portfolio

Year Annual

Participants1

Annual MW

Demand

Savings

(at Meter)

Annual MWh

Energy

Savings

(at Meter)

Annual

Rebate/

Incentive

Costs

Annual

Admin Costs2

Total Annual

Program

Costs

2015♦ 42,654 3.681 15,729 $3,250,299 $1,455,948 $4,706,247

2016♦ 44,279 5.897 18,213 $3,827,090 $1,670,719 $5,497,809

2017♦ 38,828 2.501 12,729 $2,942,309 $1,508,575 $4,450,884

2018 67,335 3.441 13,247 $3,185,274 $2,005,993 $5,191,267

2019 49,443 8.732 16,921 $3,712,277 $2,010,949 $5,723,226

2020 48,860 8.050 14,770 $3,226,728 $1,886,918 $5,113,646

2021 48,852 7.959 14,405 $3,180,466 $1,933,180 $5,113,646 1. CFL & LED Program assumes 5 bulbs per participant 2. Includes Third Party Costs, Promotion Costs, Program Development Costs, and EM&V Costs ♦ Verified by Commission approved statewide EM&V contractor

3. Texas Energy Efficiency Programs

EPE has offered EE programs in its Texas service territory since 1999. EPE's Texas

jurisdictional programs require a minimum annual demand reduction, as well as an

associated minimum energy reduction based on a 20% capacity factor. In the Final

Order of the PUCT Docket No. 47125, EPE’s annual demand reduction goal for

2017 was 11.16 MW and its energy savings goal was 19,552 MWh. EPE achieved

a demand reduction of 15.285 MW, which exceeded the demand goal by 36.96%,

and an energy reduction of 23,312 MWh, which exceeded the energy goal by


19.23%. Currently, EPE offers six residential and five commercial programs in its

Texas service territory.

Table 7 provides the actual verified demand and energy savings for EPE's Texas EE

programs for 2015 through 2017 and provides the projections for 2018 and 2019.

The 2018 and 2019 projections are based on the information provided in EPE’s

2018 Energy Efficiency Plan and Report, PUCT Project No. 48146.

Table 7 – Texas Verified and Projected Demand and Energy Savings

Year Annual MW

Demand Savings (at Meter)

Annual MWh Energy Savings

(at Meter)

2015♦ 12.305 22,283

2016♦ 12.790 22,912

2017♦ 15.285 23,312

2018 14.181 21,054

2019 14.181 21,054

♦ Verified by Commission approved statewide EM&V contractor

D. Storage Resources

Currently, EPE’s resource portfolio does not contain any storage resources. Battery storage

is a new and emerging technology that is beginning to gain entry into utility scale

applications. Battery storage is a resource that EPE is considering and will continue to

consider for future capacity expansion.


E. Reliability Requirements

EPE’s resource planning efforts also take into consideration the reliability requirements

defined by the North American Electric Reliability Corporation ("NERC"), which is

granted authority by the Federal Energy Regulation Commission ("FERC") to define

reliability standards. The reliability standards are developed to reduce risks to the

reliability and security of the grid.2 There are six reliability standards that are most

relevant to the Planning Process.

BAL-001 – "To control Interconnection frequency within defined limits."

BAL-005-0.2b – "…ensures that all facilities and load electrically synchronized to the

Interconnection are included within the metered boundary of a Balancing Area so that

balancing of resources and demand can be achieved."

BAL-006-2 – "…process for monitoring Balancing Authorities to ensure that, over the long

term, Balancing Authority Areas do not excessively depend on other Balancing Authority

Areas in the Interconnection for meeting their demand or Interchange obligations."

BAL-002 - "…to ensure the Balancing Authority is able to utilize its Contingency Reserve

to balance resources and demand and return Interconnection frequency within the defined

limits following a Reportable Disturbance."

2 NERC. https://www.nerc.com/AboutNERC/Pages/default.aspx

https://www.nerc.com/AboutNERC/Pages/default.aspx


BAL-002-WECC - "To specify the quantity and types of Contingency Reserve required to

ensure reliability under normal and abnormal conditions."

BAL-003 - "To require sufficient Frequency Response from the Balancing Authority to

maintain Interconnection Frequency within predefined bounds by arresting frequency

deviations and supporting frequency until the frequency is restored…"

TOP-001-3 - "To prevent instability, uncontrolled separation, or Cascading outages that

adversely impact the reliability of the Interconnection by ensuring prompt action to prevent

or mitigate such occurrences."

EPE efforts to ensure resource adequacy to serve peak load in a safe and reliable manner are

founded, in part, with the above mentioned reliability standards. Furthermore, 17.9.560.13

NMAC also addresses an electric utility’s requirement to provide reliable service.

"The electric plant of the utility shall be constructed, installed,

maintained, and operated in accordance with accepted good

engineering practice in the electric industry to assure, as far as

reasonably possible, continuity of service, uniformity in the quality of

service furnished, and the safety of persons and property."

Additionally, it stresses the importance of resource adequacy to include a reserve margin.

"Adequacy of supply. The generating capacity of the utility's plant

supplemented by the electric power regularly available from other

sources must be sufficiently large so as to meet all normal demands for

service and provide a reasonable reserve for emergencies."


F. Existing Transmission Capabilities

EPE owns and operates extensive transmission resources to serve customer load from its

local and remote generation, and from other interconnected resources throughout the

WECC. EPE's high voltage ("HV") transmission system consists of 69 kilovolt (“kV”) and

115 kV lines, and its extra high voltage ("EHV") transmission system consists of 345 kV,

and 500 kV lines. These facilities are located in the following locations: within the EPE

service territory, interconnected from its service territory to the western grid, or located

near EPE's remote PVNGS generation. EPE's 345 kV system is the integral part of the

transmission system used to import and export power to and from EPE’s service area.

EPE’s transmission system is comprised of three key components:

• Local transmission - Several 345 kV, 115 kV, and 69 kV transmission lines that are

interconnected within EPE's local electrical grid.

• Path 47 - Three major 345 kV transmission lines known as Path 47 used to

import/export power between WECC and EPE (plus one 115 kV line wholly owned

and utilized by Tri-State); and,

• Eddy County DC Tie - A single 345 kV transmission line that interconnects EPE's

local transmission system to SPS, an Xcel Energy Company, system through a

200 MW High Voltage Direct Current ("HVDC") terminal.

More details on EPE's transmission system are explained in the following sections.

Local Transmission


EPE's local EHV and HV transmission system consists of 345 kV, 115 kV and 69 kV

lines in and around El Paso, Texas, and Las Cruces, New Mexico. EPE’s local EHV

transmission system consists of several 345 kV transmission lines that move the power

from EPE’s Path 47 import path and the Eddy County HVDC Terminal (see below) and

distributes that power for delivery to various points on EPE’s local HV system. Most of

EPE’s major distribution substations are connected to at least two 115 kV and/or 69 kV

transmission lines. This high level of networking increases the reliability of the system

by allowing the power to re-route to other transmission lines during outages.

EPE's local generation is directly connected to the local HV transmission system at

Newman in northeast El Paso; Rio Grande in Sunland Park, New Mexico; MPS in far

east El Paso; and Copper in central El Paso. The power generated at these plants flows

directly into the EPE HV transmission system and then flows to the customer loads

through the distribution system.

Path 47

Path 47 consists of EPE's three major 345 kV transmission interconnections with other

utilities that are at the; (1) West Mesa Switching Station near Albuquerque, New Mexico

with Public Service Company of New Mexico (“PNM”); (2) Springerville Generating

Station (“Springerville”); and, (3) Greenlee Substation (“Greenlee”), (both in Arizona) with

Tucson Electric Power Company ("TEP"). Path 47 also includes the Belen to Bernardo


115 kV line owned and wholly used by Tri-State Generation and Transmission Association,

Inc. ("Tri-State").

Eddy County DC Tie

EPE connects with SPS at the Eddy County HVDC Terminal near Artesia, New Mexico

and has a 67% ownership in the Terminal and accompanying 345 kV transmission line

connecting to the EPE system along with the joint owner, PNM. Through this HVDC

Terminal, EPE can access resources, when available, in the SPP for delivery to EPE

loads.

Along with the three components listed above, EPE has ownership of external EHV

transmission, as described below.

EPE partially owns 500 kV transmission lines in the Arizona transmission system in

connection with its PVNGS ownership and uses these lines for the delivery of its owned

Palo Verde generation entitlement. These transmission lines are designated as the

Palo Verde East Path (composed of three lines, two (2) Palo Verde to Westwing lines and

the Palo Verde to Jojoba to Kyrene line) and are operated by Salt River Project (“SRP”).

EPE utilizes a combination of an exchange and transmission agreement with TEP,

transmission wheeling purchased from SRP and PNM. In addition, EPE has a PPA with

Phelps Dodge Energy Services, LLP, to import additional resources that are purchased on

the market and to allow EPE to import additional Palo Verde power during times Path 47


is curtailed. Once the power is delivered to EPE’s Balancing Area, it is delivered to

EPE’s load area through use of jointly (EPE and PNM) and wholly-owned 345 kV lines

in southern New Mexico and locally in the El Paso/Las Cruces area and then to EPE's

local HV transmission system through EPE's existing 345/115 kV auto-transformers.

A map of EPE’s EHV Transmission system is shown in Figure 2 below.

Figure 2 - EPE Transmission Rights and Ownership


Segments Which Comprise the EPE Extra High Voltage Transmission System

1. Wheeling Agreements

EPE purchases transmission to serve its native load from PNM and SRP. EPE has

executed long-term, firm point-to-point transmission service agreements with PNM

and SRP. EPE has also executed a Power Exchange and Transmission Agreement

with TEP. These services are described below:

Transmission Services Purchased by EPE from PNM

EPE has a transmission service agreement under PNM’s Open Access Transmission

Tariff (“PNM OATT”) for 104 MW firm, point-to-point transmission from FCPP

345 kV Switchyard to West Mesa 345 kV Switching Station from 07-01-2017 to 07-

01-2022. In addition, EPE has rolled over its grandfathered, firm 20 MW long-term

rights under Service Schedule I of the 1966 Interconnection Agreement between EPE

and PNM into Firm, Point-to-Point Transmission Service under PNM OATT with a

term of June 1, 2014 to June 1, 2019. Both of these transmission purchases have an

option to rollover. The Transmission Service described above is utilized by EPE to

serve its native load.


Transmission Services Purchased by EPE from SRP

EPE has a non-OATT, firm transmission service agreement for 150 MW from Kyrene

230 kV Switchyard to Coronado 500 kV Switchyard with SRP for the delivery of a

portion of EPE’s PVNGS entitlement or for the direct substitution of power and

energy from any other source to serve EPE’s native load. This Agreement remains in

effect concurrent with the Arizona Nuclear Power Project Participation Agreement,

unless earlier terminated by the parties.

Transmission Service Exchange Agreements between EPE and TEP

Under the Tucson-El Paso Power Exchange and Transmission Agreement, EPE has a

non-OATT, executed power exchange and transmission agreement with TEP in

which EPE delivers from its share of PVNGS generating units, and TEP receives,

amounts of capacity with corresponding energy at the Palo Verde Switchyard or the

Westwing Substation of 300 MW. EPE has an additional Exchange for up to

150 MW pursuant to a non-OATT agreement under the EPE-TEP Interconnection

Agreement. EPE receives such capacity and energy at Greenlee, Springerville,

Coronado, San Juan, or FCPP in total amounts equal to that scheduled to TEP at the

Palo Verde Switchyard or Westwing Substation.

Under the Tucson- El Paso Power Exchange and Transmission Agreement, TEP

assigned to EPE 150 MW of transmission rights in TEP’s 345 kV system between


Springerville and either of FCPP, San Juan, or Coronado; this assignment of rights is

bi-directional. The term of this Agreement is consistent with the life of PVNGS

Units 1, 2, and 3.

2. Existing and Under Construction Transmission Facilities

EPE's transmission facilities include transmission lines (internal and external to EPE),

substation transformers, autotransformers and a Phase Shifting Transformer at Arroyo

Substation. EPE owns and operates 224 miles of 69 kV transmission lines, 513 miles

of existing 115 kV transmission lines, and 946 miles of 345 kV transmission lines. In

addition, EPE jointly owns 165 miles of 500 kV transmission lines in Arizona.

Attachment C-1 provides information on EPE’s transmission facilities. This includes

a list of EPE’s existing and under construction transmission facilities, including

associated switching stations and terminal facilities, and transfer capability

limitations. Individual line limitations (ratings) on EPE's transmission network may

affect future siting of supply-side resources.

EPE engages in various transmission projects in its local area to maintain, upgrade,

and expand EPE's transmission system in order to ensure the reliability of the system

and to provide for future load growth. EPE produces a 10-year Transmission

Expansion Plan every year in accordance with Attachment K of EPE's Open Access


Transmission Tariff ("EPE OATT"). A summary of this plan is posted on EPE's web

site.

3. Location and Extent of Transfer Capability Limitations

EPE's primary interconnection is to the WECC. EPE's ability to import its remote

generation resources is governed by the transmission capacity of its WECC

interconnection, termed WECC Path 47 or the Southern New Mexico Transmission

System ("SNMTS"). EPE is physically interconnected to the Southwest Power Pool

("SPP") through its HVDC tie. EPE has transmission ownership of 133 MW over the

HVDC tie and ownership of 645 MW of firm capacity over Path 47.

The Total Transfer Capability ("TTC") of a transmission path is the maximum

amount of power that can be transferred on that path, i.e., from one point on the

system to another point on the system in a reliable manner while meeting all of a

specific set of defined pre-and post-contingency system conditions. This capability is

defined by the worst contingency for the defined point-to-point path and the thermal,

voltage, and/or stability limits of that path. The Available Transfer Capacity ("ATC")

is a measure of the transfer capability available on a transmission path for commercial

activity over and above already committed uses and established capacity and

reliability margins.

EPE makes ATC determinations on a real-time basis. ATC values are posted on the


OATI OASIS website for the EPE transmission system with all transmission lines in-

service. TTC, however, will change from time to time to reflect both scheduled and

unscheduled, or forced, outages. The amount of curtailments for EPE's major

transmission system outages are given on EPE's OASIS.

Brief descriptions of the Southern New Mexico Import Capability ("SNMIC") and the

capacity of EPE's external line segments are provided below.

Additional transmission data pertaining to EPE's transmission facility capability and

planning standards are posted on EPE's website at www.epelectric.com. These

include "Principles, Practices and Methods for the Determination of Available

Transmission Capacity for El Paso Electric Company" ("ATC Document") is found

on EPE’s website. The ATC Document explains EPE transmission facility

capabilities and how EPE operates its New Mexico and Texas transmission system as

a whole.

4. SNMIC Limitation Determination

Total and available transmission capabilities for the primary 345 kV path which

connects the EPE Balancing Area ("BA") to neighboring BAs operated by PNM and

TEP are based on the SNMIC. The individual lines into the EPE BA – the West

Mesa 345 kV transfer path between EPE and PNM, and the Springerville 345 kV and

Greenlee 345 kV transfer paths between EPE and TEP – are collectively referred to as

http://www.epelectric.com/


WECC Path 47, or the SNMTS. This is a WECC Accepted Path with a rating that is

less than the sum of the capabilities of the individual lines.

The SNMIC is determined through real-time dynamic nomogram equations that

incorporate the state and configuration of the southern New Mexico system at any

instant of time and by the use of dynamic adjustments, reflect changes in that system

state. These dynamic adjustments reflect southern New Mexico system variables

such as: the status and output of EPE's and other local generating units, power factor

for the EPE load area, status of 345 kV reactors in the SNMTS, and the amount and

direction of power flows over selected EPE transmission lines.

The maximum amount of firm import capability into the SNMTS over the 345 kV

interconnections (plus the capacity of the Tri-State Belen-Bernardo 115 kV line) is

940 MW. The allocation of this firm capability among the owners of the SNMTS is:

EPE 645 MW

PNM 185 MW

Tri-State 110 MW

To the extent the SNMIC decreases below the maximum firm capacity value due to a

change in the status of EPE-owned transmission variables (listed above), EPE is

obligated to decrease its portion of SNMIC. Likewise, if the status of the EPE-owned

transmission variables allow for a SNMIC greater than the maximum firm capacity of


940 MW, only EPE can use that additional capacity on a non-firm basis.

As the operating agent of the SNMTS, EPE is also responsible for notifying other

owners if their imports exceed their rights and whether curtailment of imports is

required.

5. External Transmission Limitation Determination

As mentioned above, EPE partially owns 500 kV transmission lines in the Arizona

transmission system in connection with its PVNGS ownership and uses these lines

for the delivery of its owned Palo Verde generation entitlement. Salt River Project

performs the technical studies to evaluate the Palo Verde East rating, with

agreement of the other Palo Verde East path owners, PNM, and Arizona Public

Service Company ("APS"). EPE posts this path with the ratings determined through

these studies on its OASIS. A full explanation on how TTC and ATC on these paths

are determined can be found in the ATC Document.

6. Transmission Coordinating Groups

As a Class 1 member (transmission provider) of WECC, EPE's transmission

planning activities are coordinated through several regional groups that include

WECC committees under the Reliability Assessment Committee ("RAC"). These

groups include the Anchor Data Set Task Force ("ADSTF"), the Data


Subcommittee ("DS"), Modeling Subcommittee ("MS"), Joint Synchronized

Information Subcommittee ("JSIS (RAC)"), Scenario Development Subcommittee

("SDS"), and the Studies Subcommittee ("StS"). In addition, EPE is a member of

the General Electric Users Group, the regional group WestConnect and the

sub-regional group Southwest Area Transmission ("SWAT") Planning Committee.

Through WestConnect, EPE and other WestConnect members participate in the

regional transmission planning process detailed in FERC Order 1000 and in

Attachment K of EPE’s Transmission Tariff (OATT). The WestConnect footprint

includes New Mexico, Arizona, Nevada, Colorado, and part of Wyoming, part of

California, and part of Nebraska.

Conclusion and Discussion

As described above, EPE is physically located in the far southeastern corner of the

WECC region and is constrained by transmission import limits. Firm import

transmission capacity is limited to two specific paths: Path 47 and the Eddy County

HVDC Tie. In other words, EPE is not in a position to wheel power through its

service territory from multiple transmission paths, but is more of a terminal point in

the WECC region. Import capacity outside of these paths is non-firm and cannot be

considered in long-term resource planning because availability of non-firm

transmission capacity is unknown. EPE considers these constraints when

performing its long-term planning and when establishing an appropriate reserve


margin. These considerations, in conjunction with risk of outages due to

transmission maintenance or transmission system failure, require further review

when evaluating the siting of future generation. Due to the transfer capability limits

of Path 47 and the Eddy County DC Tie, future supply side resources may be more

optimally be sited within EPE’s service territory. Any resources sited outside

EPE’s service territory likely would require transmission investments to ensure firm

transmission import capacity.

Energy Imbalance Market

As of recent years, there has been a lot of discussion associated with the California

Independent System Operator ("CAISO") Energy Imbalance Market ("EIM"). The

CAISO EIM is a real-time market allowing participating entities the ability to

leverage each other’s online and available resources to regulate and address energy

imbalances. The energy imbalances are primarily a result of the increasing variable

generation (e.g. solar and wind) which has been added to the system. It is important

to clarify that participation in the EIM does not provide additional resources for the

purpose of meeting peak load. Each participant is required to have adequate

resources to meet its peak load and regulating requirements. The EIM allows for

co-utilization of each entities regulating reserves and potentially optimize

dispatch/operating costs. It is not permitted for an entity to enter the EIM without

adequate resource supply, as it may result in a burden to the EIM. As such, utilities

are required to identify and secure adequate firm resources to meet peak load and


reserve requirements before entry.

EPE continues to monitor and consider markets such as the EIM, while continuing

with its Planning Process to plan for adequate resources to meet EPE’s load

requirements.

G. Back-Up Fuel Capabilities and Options

Table 2 identifies plants that are dual fuel capable. Further discussion on dual fuel

capability is found in Section VII, "Description of the Resource and Fuel Diversity."

IV. CURRENT LOAD FORECAST

A. Forecast Summary

The 2018 Load Forecast predicts expected, upper, and lower bounds for energy and peak

demand, for EPE’s native and total systems. The forecast is generated for the 20-year

period of 2018-2037 (see Attachment D-1). The 2018 expected (base) forecast predicts

10- and 20-year compound annual growth rates ("CAGR") of 1.2% and 1.3% for native

system energy, respectively. The 2018 expected forecast predicts 10- and 20-year CAGR of

1.3% and 1.5%, respectively, for native system peak demand. EPE’s native system

consists of New Mexico and Texas jurisdictional retail load and the contractual Rio Grande

Electric Co-Operative ("RGEC") wholesale load EPE serves interconnected to its Texas


service territory. Native system load plus line losses incurred from off-system wheeling of

EPE's power (losses-to-others) make up EPE’s total system. The following information is

provided as required by the IRP Rule, 17.7.3.9 (D).

B. Load Forecast Methodology and Inputs

EPE's 2018 Load Forecast is developed from a number of components. The forecast takes

into consideration factors such as historical energy sales, average weather, demographic

trends, economic activity, existing rate design, distributed solar generation, energy

efficiency, saturation of refrigerated air conditioning, and potential changes in customers.

The largest component of the load forecast is the econometric modeling of retail energy

sales. Econometrics is the application of mathematics and statistical methods to conduct

economic analyses and developing forecast trends. EPE uses econometrics to provide an

empirical estimate of the relationship between economic, weather, and demographic data,

and electricity consumption. EPE's econometric forecasting models relate customer

electricity usage to service area trends in population, weather, and local economic

indicators to estimate future electricity sales. For example, population, personal income,

and weather are typical drivers of electricity sales; more customers and increased income to

purchase appliances will typically result in higher electricity demand. The primary data

sources for EPE’s econometric models are IHS Economics, NOAA (National Oceanic and

Atmospheric Administration), AccuWeather, and EPE’s customers’ historical usage/load

data. IHS Economics provides the underlying assumptions of the economic and


demographic data that are used in developing EPE's forecasted energy and peak demand.

NOAA and AccuWeather provide EPE with regional weather data used in weather

normalizing historical sales and producing "normal" weather values for the forecast period.

EPE also uses the historical usage/load data for each of its major customer classes.

The 2018 Load Forecast employs monthly and annual methodologies to develop its models

for EPE’s major customer classes. The monthly energy forecasts are based on econometric

modeling of the residential, small commercial & industrial, and government load sectors in

both Texas and New Mexico. The annual energy forecasts are based on econometric

modeling of the large commercial & industrial sectors for both Texas and New Mexico for

a total of eight separate econometric energy forecasts. Each of the eight models is

estimated using Ordinary Least Squares as a function of weather, economic, and

demographic variables.

The Residential class energy sales are estimated utilizing a use per customer ("UPC")

methodology. The estimated UPC is then multiplied by the customer count forecast to

arrive at a total kWh forecast for this customer class. The energy forecasts for small

commercial & industrial, large commercial & industrial, and government classes are

estimated using total kWh. The final models are selected based on various key measures

such as R2, t-statistics, the Durbin-Watson test, and the F-statistic.

The customer count forecast equations are also estimated for each of the customer classes

using econometric models, except for the large commercial & industrial class. This class


has a small number of customers, whose energy consumption and demand vary

significantly among individual customers. The number of large commercial & industrial

customers is set at current levels, unless it is known that specific customers are planning to

enter or leave the service territory at a specific future date. For these reasons, EPE

maintains a customer count for this class constant with 2017 year ending levels.

In instances where adequate data is not available to support econometric forecasts, EPE

relies on sales estimates based upon recent experience, and information from large

industrial customers to make adjustments that are based on known or expected changes in

load. Examples of these adjustments in the 2018 Load Forecast include changes in load at

military installations, distributed solar generation, and energy efficiency.

The econometric sales forecasts are adjusted to reflect energy efficiency and distributed

solar generation effects not represented in the historical database. Energy efficiency effects

include the results of EPE-sponsored energy efficiency programs that are required in its

Texas and New Mexico jurisdictions. The distributed generation effects take into account

customer owned solar generation in the residential, small commercial & industrial, and

government customer classes. The estimates for energy efficiency energy savings and

distributed generation energy impacts are accounted for in the annual retail sales energy

forecasts in developing the expected native system energy value. In addition to these

adjustments, the contractual RGEC load is also incorporated into the forecast; RGEC is a

wholesale/native load customer.


EPE combines annual retail sales with sales to RGEC, company use, energy efficiency, and

distributed generation and then calculates native system losses using a system line loss rate.

These system losses must be included with sales at the meter to accurately calculate the

total energy requirement needed to deliver electricity to EPE's customers. Additionally,

line losses are incurred from off-system wheeling of EPE's power (losses-to-others). These

losses are estimated based on historical trends of the system and are added to the native

system energy to arrive at the total system energy value.

After the energy forecast is calculated, a constant native system load factor is applied to the

native system energy to calculate the expected native system peak demand over time.

Mathematically, the load factor equation is:

LF = Energy / (Demand x Hours)

Solving for Demand, the equation becomes

Demand = Energy / (LF x Hours)

The constant load factor methodology utilizes the native system load factor from the

previous year and applies it to the native system energy forecast to create the annual native

system peak demand forecast. As is done with the expected native system energy, the

expected native system peak demand is also adjusted for energy efficiency and distributed


solar generation measures that impact system demand. The estimated peak demand for

both interruptible customers and wheeling losses-to-others are then accounted for to obtain

the total system peak demand.

C. Weather Adjustment Detail

Weather is a major factor in determining EPE’s energy sales and peak demand. The 2018

Load Forecast assumes that 10-year average weather conditions (2008-2017) exist

throughout the forecast period (2018-2037). The 10-year average weather data is used as a

baseline for comparing current weather data and creating "normal weather" conditions in

the forecast period.

The two weather variables most significant to the energy models are Heating Degree Days

(HDD) and Cooling Degree Days (CDD). The HDD and CDD variables are based on a

65°F base. That is, if the average temperature for the day (maximum plus minimum,

divided by two) is over 65°F, the difference is the number of CDD for that day. Likewise,

if the average is less than 65°F, the difference is the number of HDD for that day.

Because CDD and HDD are recorded on a calendar month basis while booked month sales

are recorded over 18 billing cycles that normally include portions of two calendar months,

it was necessary to adjust these calendar month variables into variables that correspond to

EPE's billing cycles. This adjustment was accomplished through the use of two month

moving average CDD and HDD variables.


D. Demand-Side Savings Detail

EPE’s energy and demand forecasts are adjusted to reflect EPE-sponsored Energy

Efficiency programs that are required in EPE’s Texas and New Mexico jurisdictions.

EPE’s Energy Efficiency department develops these savings by jurisdiction and customer

class.

EPE does not directly adjust its forecast models for demand-side savings that are not

attributable to actions by EPE. Demand-side management that is attributable to actions

other than EPE, such as consumers who, without any EPE incentive, decide to transition to

lower wattage light bulbs or energy efficient appliances, have savings that are

unquantifiable. However, the historical sales data used in EPE’s econometric forecasts

does have embedded in it any organic or naturally occurring demand-side savings that may

have occurred. Therefore, through the use of historical data, EPE’s models and forecasted

estimates of energy and demand do indirectly account for organic demand-side

management.

E. Distributed Generation


EPE’s forecast future customer count growth, sales, and generation capacity (nameplate

and production at the time of system peak) for customers who own or lease distributed

generation solar systems. These projections are made monthly for a 20 year period

(2018-2037) by jurisdiction and by impacted customer classes. The econometric sales and

demand forecasts are adjusted to reflect these forecasted distributed generation effects that

are not represented in the historical database.

The distributed generation effects take into account customer owned or leased solar

generation in the residential, small commercial & industrial, and government customer

classes. Customer forecasts for the above mentioned customer classes drive the final

energy and demand estimates for distributed generation. The median nameplate capacity

for distributed generation systems in the region along with their observed capacity factors

are applied to these customer forecasts to arrive at the energy and demand forecasts. A

coincidence factor of 47 percent is used to account for the expected production of

distributed generation systems at the time of the system peak relative to the maximum total

production capacity of these units. Furthermore, an annual degradation factor of

0.5 percent is used to account for the degradation in the output of solar panels over time.

The estimates for distributed generation energy impacts are accounted for in the annual

retail sales energy forecasts in developing the expected native system energy value.

The econometric sales and demand forecasts are adjusted to reflect future distributed

generation effects not represented in the historical database.


F. Load Forecast Scenarios

In addition to the expected (base) estimates, the 2018 Load Forecast also estimates both

upper and lower (high and low) scenarios. These upper and lower scenarios are produced

for both native system energy and native system peak demand to account for future

uncertainty. Upper and lower scenarios around energy and demand base forecasts can be

estimated in various ways; such as by using statistical methods as well being driven by

extreme weather scenarios. EPE calculates upper and lower scenarios using confidence

intervals as well as a variety of extreme weather scenarios. Both the upper and lower

scenarios shown in Attachment D-1 are built using a confidence interval with a 95%

confidence level. EPE uses confidence intervals with a high confidence level as the

preferred method for building upper and lower bands because it captures more uncertainty

in future periods. The increased uncertainty helps capture possible future changes to

electricity consumption in addition to that of weather, such as: changes in rate structures,

economy, demography, and taste and preferences. Although EPE uses confidence intervals

to produce the upper and lower case forecasts in the 2018 Load Forecast, EPE also has

provided below upper and lower case forecasts using extreme historical weather for

comparison purposes. These scenarios pull the most extreme historical weather months

over a 10-year historical period, both on the high and low side, and combine them to form a

calendar year of the most extreme monthly weather. This weather is then applied to future

years to produce energy and peak demand estimate bands around the expected case.

Figures 3 and 4 below contain a graphical representation of the low and high forecast

scenarios of native system energy and native system peak demand.


Figure 3 - Native System Energy Forecast Scenario Comparison

Figure 4 - Native System Peak Demand Forecast Scenario Comparison


From Figures 3 and 4 above, one can see that the extreme weather upper and lower bands

(Upper-10 YR and Lower-10 YR) are narrower than that of the confidence interval bands

(Upper-CI and Lower-CI). As mentioned previously, EPE constructed confidence intervals

with a high confidence level to capture more uncertainty in future periods. The increased

uncertainty helps capture possible future changes to electricity consumption in addition to

extreme weather, such as: changes in rate structures, economy, demography and taste and

preferences.

EPE’s expected forecast predicts 10- and 20-year CAGR of 1.2% and 1.3% for native

system energy, respectively. The expected forecast also predicts 10- and 20-year CAGR of

1.3% and 1.5%, respectively, for native system peak demand. The upper forecast scenario

predicts 10- and 20-year CAGR of 1.5% and 1.5% for native system energy, respectively.

The upper forecast also predicts 10- and 20-year CAGR of 1.9% and 1.7%, respectively,

for native system peak demand. The lower forecast scenario predicts 10- and 20-year

CAGR of 0.8% and 1.1% for native system energy, respectively. The lower forecast

scenario predicts 10- and 20-year CAGR of 0.7% and 1.2%, respectively, for native system

peak demand.

G. Historical Forecast Accuracy and Comparison

Tables 8 and 9 below contain the annual forecast of energy sales and system peak demand

made by EPE to the actual energy sales and system peak demand experienced by EPE for


the four years preceding 2018, (2014-2017). Please note that the energy data in Table 8 is

total energy sales, which is composed of energy sales "at meter" for both retail and

wholesale customers.

Table 8 - Total Sales (MWh) Historical Forecast Accuracy

Table 9 - Native System Demand (MW) Historical Forecast Accuracy

2014 2015 2016 2017Actual 7,687,369 7,867,229 7,874,577 7,820,929

2014 Forecast 7,932,225 8,053,832 8,169,030 8,290,368 2015 Forecast 7,825,953 7,918,635 8,046,366 2016 Forecast 7,956,182 8,078,403 2017 Forecast 7,967,828

2014 Forecast 3.19% 2.37% 3.74% 6.00%2015 Forecast -0.52% 0.56% 2.88%2016 Forecast 1.04% 3.29%2017 Forecast 1.88%

Total Sales (MWH) Historical Forecast Accuracy

Percent Difference

2014 2015 2016 2017Actual 1,766 1,794 1,892 1,935

2014 Forecast 1,784 1,812 1,834 1,867 2015 Forecast 1,804 1,822 1,857 2016 Forecast 1,811 1,846 2017 Forecast 1,927

2014 Forecast 1.02% 1.00% -3.07% -3.51%2015 Forecast 0.55% -3.72% -4.01%2016 Forecast -4.29% -4.60%2017 Forecast -0.43%

Native System Demand (MW) Historical Forecast Accuracy

Percent Difference


Table 10 below contains a comparison of the annual forecast of energy sales and system

peak demand in EPE’s most recently filed resource plan (2015) to the annual forecasts in

the current resource plan (2018).

Table 10 - Annual Forecast Energy Sales Versus Peak Demand

2015 Forecast 2018 Forecast2015 7,825,953 2016 7,918,635 2017 8,046,366 2018 8,166,772 8,538,570 2019 8,282,077 8,627,426 2020 8,391,194 8,710,205 2021 8,502,795 8,795,702 2022 8,619,449 8,899,003 2023 8,738,919 9,007,162 2024 8,858,544 9,112,225 2025 8,979,482 9,220,050 2026 9,102,242 9,334,948 2027 9,262,583 9,453,634 2028 9,425,859 9,572,353 2029 9,589,993 9,700,029 2030 9,759,477 9,840,094 2031 9,916,510 9,973,737 2032 10,084,389 10,118,180 2033 10,258,113 10,272,049 2034 10,434,535 10,433,457 2035 10,598,093 2036 10,769,465 2037 10,950,123

Total Energy Sales Forecast Comparison (MWh)2015 Forecast 2018 Forecast

2015 1,804 2016 1,822 2017 1,857 2018 1,887 1,964 2019 1,914 1,988 2020 1,935 2,005 2021 1,968 2,034 2022 1,996 2,061 2023 2,025 2,090 2024 2,048 2,111 2025 2,083 2,146 2026 2,113 2,176 2027 2,144 2,206 2028 2,169 2,231 2029 2,206 2,270 2030 2,239 2,306 2031 2,269 2,340 2032 2,295 2,370 2033 2,335 2,416 2034 2,370 2,456 2035 2,498 2036 2,533 2037 2,586

Peak Demand Forecast Comparison (MW)


V. LOAD AND RESOURCES TABLE

The L&R illustrates the balance of EPE’s available resources versus the annual forecasted loads.

EPE’s long-term future resource needs are driven by unit retirement and also system load

growth. Forecasted loads are based on the 2018 Load Forecast for the L&R.


Table 11 - Initial L&R

Loads & R

esources 2018-2037Initial 2018 IR

P

20182019

20202021

20222023

20242025

20262027

20282029

20302031

20322033

20342035

20362037

1.0 GENERATIO

N RESOURC

ES 1.1 R

IO G

RA

ND

E321

276

276

276

276

230

230

230

230

230

230

230

230

230

230

230

88

88

88

88

1.2 N

EW

MA

N752

752

752

752

752

602

602

602

602

278

278

278

278

278

278

278

278

278

278

278

1.3 C

OP

PE

R64

64

64

64

64

64

64

64

64

64

64

64

64

-

-

-

-

-

-

-

1.4 M

ON

TAN

A354

354

354

354

354

354

354

354

354

354

354

354

354

354

354

354

354

354

354

354

1.5 P

ALO

VE

RD

E633

633

633

633

633

633

633

633

633

633

633

633

633

633

633

633

633

633

633

633

1.6 R

EN

EW

AB

LES

6

6

6

6

6

6

6

6

6

6

6

6

6

6

6

6

6

6

6

6

1.7 STO

RA

GE

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

1.8 PO

SS

IBLE

EM

ER

GIN

G TE

CH

EX

PA

NS

ION

(1)-

-

-

-

40

40

40

40

40

40

40

40

40

40

40

40

40

40

40

40

1.9 N

EW

BU

ILD (local)

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

1.0 TOTAL G

ENERATION RESO

URCES

(2)2,130

2,085

2,085

2,085

2,125

1,929

1,929

1,929

1,929

1,605

1,605

1,605

1,605

1,541

1,541

1,541

1,399

1,399

1,399

1,399

2.0 RESOURC

E PURCHASES

2.1 RE

NE

WA

BLE

PU

RC

HA

SE

(SunE

dison & N

RG

)29

29

29

29

28

28

28

28

27

27

27

27

27

26

26

26

26

26

25

25

2.2 R

EN

EW

AB

LE P

UR

CH

AS

E (H

atch)4

3

3

3

3

3

3

3

3

3

3

3

3

3

3

3

3

3

3

3

2.3 R

EN

EW

AB

LE P

UR

CH

AS

E (M

acho Springs)

35

35

34

34

34

34

34

34

33

33

33

33

33

33

32

32

32

32

32

32

2.4 RE

NE

WA

BLE

PU

RC

HA

SE

(Juwi)

7

7

7

7

7

7

7

7

7

7

7

7

7

7

6

6

6

6

6

6

2.5 RE

SO

UR

CE

PU

RC

HA

SE

-

-

-

-

10

-

30

65

105

45

90

130

-

-

5

-

-

-

20

2.0 TOTAL RESO

URCE PURC

HASES (4)

75

74

73

73

82

72

71

101

136

175

114

159

199

68

68

72

67

67

66

86

3.0 TOTAL NET RESO

URCES (1.0 + 2.0)

2,205

2,159

2,158

2,158

2,207

2,001

2,000

2,030

2,065

1,780

1,719

1,764

1,804

1,609

1,609

1,613

1,466

1,466

1,465

1,485

4.0 SYSTEM D

EMAND

4.1 N

ATIV

E S

YSTE

M D

EM

AN

D1,972

2,0042,028

2,0652,100

2,1362,166

2,2072,245

2,2832,316

2,3622,406

2,4482,485

2,5382,586

2,6352,678

2,738 4.2 D

ISTR

IBU

TED

GE

NE

RA

TION

(3)

(6)

(9)

(12)

(15)

(18)

(21)

(24)

(27)

(30)

(33)

(36)

(39)

(42)

(45)

(48)

(50)

(53)

(56)

(59)

4.3 EN

ER

GY E

FFICIE

NC

Y(5)

(9)

(14)

(19)

(23)

(28)

(33)

(38)

(42)

(47)

(52)

(56)

(61)

(66)

(70)

(75)

(80)

(84)

(89)

(94)

4.4 LIN

E LO

SS

ES

(6)

(6)

(6)

(6)

(6)

(6)

(6)

(6)

(6)

(6)

(6)

(6)

(6)

(6)

(6)

(6)

(6)

(6)

(6)

(6)

4.5 INTE

RR

UP

TIBLE

SA

LES

(54)

(54)

(54)

(54)

(54)

(54)

(54)

(54)

(54)

(54)

(54)

(54)

(54)

(54)

(54)

(54)

(54)

(54)

(54)

(54)

5.0 TOTAL SYSTEM

DEM

AND (4.1-(4.2+4.3+4.4+4.5

1,904

1,928

1,945

1,973

2,001

2,028

2,050

2,084

2,114

2,145

2,169

2,209

2,244

2,279

2,308

2,354

2,395

2,436

2,472

2,524

6.0 MARG

IN OVER TO

TAL DEM

AND (3.0 - 5.0)

301

231

213

184

207

(27)

(49)

(54)

(49)

(365)

(450)

(444)

(440)

(669)

(700)

(742)

(929)

(970)

(1,007)

(1,039)

7.0 PLANNING RESERVE 15%

286

289

292

296

300

304

307

313

317

322

325

331

337

342

346

353

359

365

371

379

8.0 MARG

IN OVER RESERVE (6.0 - 7.0)

16(58)

(78)(112)

(94)(332)

(357)(367)

(367)(686)

(775)(775)

(777)(1,011)

(1,046)(1,095)

(1,288)(1,336)

(1,378)(1,418)

1. Em

erging technologies may include custom

er or other distributed resources as well as additional com

munity solar.

Unit R

etirements

Com

pany Ow

ned Renew

ables2. G

eneration unit retirements denoted by m

ost recent planned retirement dates at start of the IR

P process.

Rio G

rande 6 (45MW

) - Denoted in 2018

3R

enewable R

esources shown in line item

1.6 consists R

etirements planned w

ithin 5 years will be analyzed in the capacity expansion m

odel per Joint Stipulation C

ase No. 15 00241 U

T. R

io Grande 7 (46M

W) - D

ecember 2022

of EP

E C

omm

unity Solar, H

olloman S

olar, EP

CC

, 3. R

io Grande 6 capacity is denoted in the 2018 plant capacity total, pending conclusion of 2018 IR

P.

New

man 1 (74M

W) - D

ecember 2022

Stanton, W

rangler, Rio G

rande & N

ewm

an Carports,

Previously identified as retired in 2014 and utilized as inactive reserve. P

er Com

mission order in docket 17-00317-U

T Rio G

rande 6 is included.N

ewm

an 2 (76MW

) - Decem

ber 2022 and V

an Horn

4. Purchases based on existing and estim

ated future purchases including renewable purchases to m

eet RP

S requirem

ents.N

ewm

an 3 (97MW

) - Decem

ber 20265. S

ystem D

emand based on2018 Long-term

and Budget Year Forecast.

New

man 4 C

C (227M

W) - D

ecember 2026

The Resource P

urchase is supported by Includes state-required targets for E

nergy Efficiency.

Copper (64M

W) - D

ecember 2030

firm transm

ission through (i) simultaneous buy/sell

Interruptible load reflects current contracts.R

io Grande 8 (142M

W) - D

ecember 2033

with Freeport M

cMoR

an (formerly P

helps Dodge),

Renew

able Purchases (ii) Four C

orners switchyard after Four C

ornersS

unEdison, N

RG

, Macho, N

ewm

an and Hatch solar

retires, and (iii) SP

S via the E

ddy Tie. purchases reflect 70%

availability at Peak.


Section 1.0 – Generation Resources

Lines 1.1 through 1.4 of the L&R reflect EPE’s generation resource capacity for EPE’s local

natural gas units. Line 1.5 identifies the PVNGS unit data.

Line 1.6 illustrates EPE’s small company owned solar facilities, including the recently added

Texas Community Solar project and the planned HAFB Solar project. Line 1.7 has been added

specifically for storage resources which may be added as a future resource. Line 1.8 has been

added to denote capacity being designated for emerging technology resources which may include

resources such as distributed generation, community solar, battery storage, or other emerging

technologies or applications.

Line 1.9, titled New Build, is a placeholder for future expected capacity additions. These

additions can be comprised of conventional and renewable resource additions. The results from

this Planning Process will be included in this line item. However, since EPE is a regulated

entity, new resource additions must be selected through a competitive bid or RFP process

(i.e., most cost effective). Thus, the resource additions may be modified in the future based on

the associated RFP processes and will result in adjustments to the L&R.

Section 2.0 – Resource Purchases

Purchases shown in lines 2.1 through 2.5 of the L&R are based on existing PPA contracts

(NRG, Hatch, SunEdison, Macho Springs, and Newman), or estimates of potential purchases


needed to cover projected capacity shortfalls to meet EPE’s load and reserve requirement in any

of the years studied in the L&R. The contribution to peak of the solar purchases are based on

70% of rated capacity based on the historical performance of EPE’s existing solar facilities at the

time of EPE’s system peak. The capacity data for the solar units also reflects the long-term

degradation estimated for each facility. The resource purchases shown on line 2.5 are estimated

based on the short-term requirements in order to serve load during summer peaking conditions.

Section 3.0 – Total Net Resources

This line is the sum of Sections 1.0 and 2.0.

Section 4.0 – System Demand

System Load Data is based on the 2018 Load Forecast. In addition to expected native system

demand, the forecast includes estimates for distributed generation, energy efficiency, and line

losses. The 2018 Load Forecast incorporates state-required energy efficiency capacity targets

mandated to reduce energy consumption. The 2018 Load Forecast also includes estimates of

interruptible load based on current contracts.

Section 5.0 – Total System Demand

This line is the sum of the line items in Section 4.0.


Section 6.0 – Margin Over Total Demand

This line is the difference of between Section 3.0 and Section 5.0.

Section 7.0 – Planning Reserve

This line reflects EPE’s 15% planning reserve margin requirement criterion based on Section

5.0.

Section 8.0 – Margin Over Reserve

This line is the difference between EPE’s margin over total demand (Section 6.0) and its

planning reserve requirement (Section 7.0).

VI. IDENTIFICATION OF RESOURCE OPTIONS (EXISTING CHARACTERISTICS

AND INTERACTIONS)

A. Supply Side Resources

The Planning Process included a variety of resource options that are described within this

section. However, there were three resource options excluded as part of EPE’s IRP

consideration. Given EPE’s existing resource portfolio, additional baseload generation is


not required. Therefore, new coal or nuclear options were not considered. Additionally,

given EPE’s geographical location, hydro resources were also not considered.

EPE utilized Lazard’s 2017 Levelized Cost of Energy Analysis Version 11.0 and Lazard’s

2017 Levelized Cost of Storage Analysis Version 3.0 as a reference for capital costs, fixed

O&M, and variable O&M. However, adjustments were made based on PAG input and

consideration of additionally available public information resulting in reasonable cost

assumptions. Resources with cost assumptions different to Lazard’s are described within

their sections.

1. Solar Photovoltaic Resource Options

EPE included several utility scale solar PV resource options for analysis. The solar

PV options included are based on 25, 75, and 100 MW capacity variations. These

resources are based on single-axis tracking systems. A generic hourly generation

profile based on EPE’s existing solar PV facilities was utilized to model the

operational characteristics of a solar resource in EPE’s region. Solar PV resources

are non-dispatchable and dependent on solar irradiance, which is impacted by

location and weather (cloud cover, rain, and/or overcast conditions). These

characteristics of solar PV lead to the resource creating variability in the electric

utility system. This variability requires additional consideration when planning and

integrating this type of resource. If a resource has an output that is variable, then


contribution at peak, and firm backup capacity must be considered to plan for system

reliability. See the Table 12 below for Solar PV resource input assumptions.

EPE initially estimated solar capital investment costs to be $1,450/kw based on

Lazard’s Levelized Cost of Energy Analysis – Version 11.0. Upon considering the

benefits of the federal Solar Investment Tax Credit (“ITC”), EPE adjusted the solar

capital costs from $1,450/kw down to $1,384/kw. Given the latest Lazard’s

Levelized Cost of Energy Analysis (“LCOE”) analysis, EPE once again reduced the

solar capital costs to $1,100/kw which is the low end of the costs range shown in the

report.

EPE also analyzed Solar PPA(s). The PPA option forecasted price drops through

2024 and remains at that level beyond 2024 based on solar PV costs that appear to be

flattening. Three solar PPA options were included at 25, 75, and 100 MW capacity

variations. The PPA options were modeled at $21.50, and remained at that price

throughout the Planning Horizon, based on publicly available information such as

forecasts for solar costs3 and regulatory filings from other jurisdictions.

2. Solar Coupled with Battery Storage

Solar PV coupled with battery storage is currently eligible for ITC benefits when

charged by solar. Given this, it is necessary to model this combination of resources

3 NREL (National Renewable Energy Laboratory). 2017. 2017 Annual Technology Baseline. Golden, CO: National Renewable Energy Laboratory. http://www.nrel.gov/analysis/data_tech_baseline.html.


as a "resource type" in order to capture the cost benefits. Lazard does not list a

solar-battery storage option. EPE introduced a 100 MW solar facility with a 30 MW

four hour battery storage option into the model for consideration. Based on research

of publicly available information4, EPE determined that the solar and storage resource

options’ PPA price should be modified to $35.74/MWh.

3. Wind Resource Options

EPE included a 100 MW nameplate wind resource option. EPE utilized a generic

hourly generation profile from National Renewable Energy Laboratory to model the

operational characteristics of a wind resource in EPE’s region. Wind, much like solar

PV, is also a variable resource that can be impacted by weather conditions. Wind

resources also require consideration for firm peak contribution, and firm back-up

capacity for system reliability. See the Table 12 below for Wind resource input

assumptions. EPE modeled these Wind projects based on current available price

trends and forecasts. Based on NREL research data5 and the latest Lazard LCOE

analysis, EPE incorporated this resource into the model with a capital expenditure

price of $1,200/kw and holding that price firm beyond 2024. This approach is based

on capital cost forecasts which are predicting flattening cost declines.

4 Cole, Wesly J. NREL (National Renewable Energy Laboratory). 2016. Utility-scale Lithium-Ion Storage Cost Projections for Use in Capacity Expansion Models. Golden, CO: National Renewable Energy Laboratory. 5 NREL (National Renewable Energy Laboratory). 2017. 2017 Annual Technology Baseline. Golden, CO: National Renewable Energy Laboratory. http://www.nrel.gov/analysis/data_tech_baseline.html.


4. Biomass Resource Option

A Biomass resource burns renewable waste (solid waste and/or landfill gas) to

generate electricity in a combustion turbine or reciprocating engine. This type of

resource is considered a base-load resource, usually with a high capacity factor.

Generally, biomass resources are dispatchable and typically not subject to much

variability. Resources with these types of characteristics are easier to integrate into

the electric utility system because their generation is firm, predictable, and

dispatchable. EPE modeled a 20 MW Biomass resource for this IRP. See the Table

12 below for Biomass resource input assumptions.

5. Geothermal Resource Option

Geothermal energy is a renewable resource type that uses heat from the Earth to

generate electricity. A geothermal resource is generally considered a base-load

resource with a high capacity factor. However, geothermal resources can be

dispatchable. EPE modeled a 20 MW geothermal resource for this IRP. See the

Table 12 below for the geothermal resource input assumptions.

6. Combined Cycle Resource Option

Combined Cycle (CC) power plant units have become larger in capacity as this

generation technology has advanced due to economies-of-scale and improvements in


efficiency. Traditionally, CCs were developed and utilized as base-load resources.

However, as technology has advanced, these units have become more flexible with

fast-start and quick ramping capabilities. CCs provide low heat rate, high efficiency

firm capacity and energy, with the ability to follow load. These operating

characteristics pair up well with other resources, especially those whose output is

variable and require firming up. For this IRP, EPE modeled a 320 MW CC. See the

Table 12 below for the CC resource input assumptions.

7. Combustion Turbine Resource Option

Combustion Turbine (“CT”) power plants have had widespread use since the 1940s.

CT units also have advanced due to technology improvements. Like the CCs, these

improvements have led to lower capital cost and enhanced efficiency. CT units have

become more flexible with fast-start and quick ramping capabilities, like the larger

CC units. CTs also provide firm capacity and energy with the ability to follow load.

For this IRP, EPE modeled a 100 MW CT. See the Table 12 below for the CT

resource input assumptions.

8. Gas Reciprocating Resource Options

Gas Reciprocating (“Recips”) engines offer characteristics that are similar to CT

units. Recips are flexible and also offer fast-start capabilities. Gas recips are modular

in size and can create many different capacity configurations. This allows low


minimum capacities and wide capacity output ranges. Gas recips also provide firm

capacity and energy with the ability to follow load. For this IRP, EPE modeled two

gas recip capacity options, 50 and 100 MW. See the Table 12 below for the recip


B. Energy Storage

BATTERY RESOURCE OPTION

Energy Storage, specifically Lithium-Ion Battery Storage, is a quickly evolving technology.

Battery storage is starting to find its place as a feasible electric utility scale resource.

Battery storage offers many benefits that complement renewable resources as well as load

shifting or load following during peak hours. However, it is important to note that the

round-trip efficiencies of batteries may be between 80 to 85 percent. Batteries are

dispatchable and offer capacity that is very similar to traditional peaking units when

dispatched to meet daily peak loads. These characteristics complement renewables, like

solar, by firming up capacity during peak conditions and offsetting variability. The capital

cost of batteries has been trending downward recently as technology and production has

improved.

Several inherent characteristics of this technology are important when considering Battery

Storage as a resource. First, battery nameplate capacity, or MW available to serve demand

which are stored in the battery. Secondly, battery duration, which is the length of time


(typically in hours) that the storage system can provide output to the electrical grid

system. Lastly, total energy stored in the battery, MWh, typically this is the nameplate

capacity times the hours of duration. The battery Storage resource modeled in the 2018

IRP is a 50 MW nameplate battery with a four (4) hour duration. A battery with these

characteristics would have a total energy level available for dispatch of 200 MWh.

As battery costs continue to decrease, they will become a more viable resource option in

expansion planning and will be further incorporated into future optimal resource portfolios,

specifically due to their interaction with renewables and load shifting. See the Table 13

below for the Storage (Battery) resource input assumptions.

C. Demand Side Resources

ENERGY EFFICIENCY RESOURCE OPTION

Existing characteristics and interaction in addition to current Energy Efficiency programs

already in place, EPE included an energy efficiency resource based on assumptions for a

commercial third-party managed program. This resource represents a summer peak load

reduction program. Summer load reduction will be achieved with energy efficiency

initiatives focused on daytime Heating, Ventilation, and Air Conditioning (“HVAC”),

lighting, and insulation. The modeled program starts at 2 MW and grows to 10 MW at a

rate of 2 MWs per year. EPE utilized programs and costs estimates from both Texas and


New Mexico to develop a resource option for both jurisdictions. See the Table 12 below

for the Energy Efficiency resource input assumptions.

DEMAND RESPONSE RESOURCE OPTION

EPE also included a Demand Response ("DR") resource for consideration in the most cost

effective portfolio analysis. This resource is based on expansion of EPE’s current

Commission approved DRPP. When considering DR as a resource, it is important that

events are limited and subject to customer acceptance. When a DR event is called,

customers have the choice to allow for the interruption or to opt out. If customers decide to

opt out, the resource’s contribution to peak will be limited. Furthermore, if a DR event

were to last multiple hours, customers who did not opt out may start using energy before

the event ends, which would increase system load.

EPE modeled a 5 MW expansion DR resource and considered forcing in the resource

instead of allowing for portfolio optimization. EPE examined information for viable

demand response programs by taking into account adoptions rates within EPE’s service

territory to determine possible resource assumptions. See the Table 12 below for the DR



Table 12 – IRP Resource Options Input Assumptions

Note:

(1) Renewables to be considered are in addition to and above Renewable Portfolio Standard requirements, as

per Joint Stipulation Case No. 15-00241-UT.

(2) Demand Response O&M costs include customer incentives.

(3) Source is Lazard’s Levelized Cost of Energy Analysis – Version 11.0 as well as other publicly available

information and EPE relative experience.


Table 13 – Storage Resource Option Input Assumptions

Note:

(1) Source is Lazard’s Levelized Cost of Storage Analysis – Version 3.0.

Table 14 below outlines modeling input assumptions related to number of options the

model is available to add throughout the study period. These inputs are necessary to the

model in order to improve runtime while providing the model viable options that may

address the resource need with either stand alone or an aggregate combination of resource

options.


Table 14 – IRP Resource Options Input Assumptions

EXISTING RATES AND TARIFFS THAT INCORPORATE LOAD MANAGEMENT

CONCEPTS

17.7.3.9.F(3) NMAC, (“IRP Rule”) requires that EPE describe in its Plan “existing rates and

tariffs that incorporate load management or load shifting concepts” as well as “how changes in

the rate design might assist in meeting, delaying or avoiding the need for new capacity”. This

section includes the information required by the Rule for EPE’s service territory generally, with

more specific information included where rate and rate structure differences exist across

jurisdictions. EPE attempts to provide rates and rate structures consistently across its entire

jurisdiction, especially as those rates and rate structures are intended to provide pricing and


options designed to enable and incentivize economic decisions by customers with implications

for the entire EPE system.

EPE's base rates are designed to recover the cost of providing electric service, including

generation, transmission and distribution costs and associated O&M expenses; general and

administrative expenses; depreciation expense; taxes and an allowed rate of return on rate base.

In New Mexico, fuel and purchased power costs are recovered through a Fuel and Purchased

Power Cost Adjustment Clause ("FPPCAC") on a monthly basis, in accordance with 17.9.550

NMAC requirements. In Texas, fuel costs are recovered through a Fixed Fuel Factor in

accordance with regulatory requirements. EPE's approved tariff schedules offer options to

customers, including time-of-use ("TOU") alternatives that provide pricing intended to

communicate differentials in the cost of providing electric service and to encourage customers to

shift energy use to off-peak periods. These pricing differentials reflect, to the extent practical

and contingent on regulatory approval, the differences in cost associated with serving load at

different times of the year (seasonal) and day.

Rate Structures Incorporating Load Management or Load Shifting Concepts

New Mexico rate structures are described as follows:

Seasonal Rates – Rate differentials between summer and winter usage are provided for all

non-lighting rates. These seasonal differentials were designed to incentivize energy

efficiency and conservation during the summer peak season.

TOU Rates – Rate classes with a TOU rate option are the Residential Service, General

Service, Irrigation Service and Military Research & Development Rates. The standard

Large Power Service and State University Service rates are TOU rates. TOU rates


contain price differentials between kWh during on-peak and off-peak hours to send

more accurate price signals by reflecting cost of service differences during specific

peak hours. TOU price differentials were designed to enable and incentivize

consumption changes. This type of rate requires more sophisticated metering for most

customers. Changes in peak use by all customers, but particularly larger commercial,

industrial and irrigation customers, may reduce purchased power costs and/or delay

additional generation resources.

Interruptible Rates – EPE offers a Noticed Interruptible Rate option for large commercial,

industrial and institutional customers. Unlike the other options described above, the

Noticed Interruptible program provides for additional system capacity on an

emergency basis only. EPE has implemented a curtailable load option for Residential

and small commercial customers on a pilot basis, which is discussed in more detail

below.

EPE's current rates were implemented pursuant to the Final Order in NMPRC Case No. 15-

00127-UT in New Mexico and Docket No. 48631 in Texas. The rates and rate differentials

contained in the current rate structures are intended to incentivize energy efficiency, energy

conservation and load shifting by customers. The price signals specifically target the afternoon

hours of the summer months, when EPE's system peaks. These higher prices during on-peak

periods incentivize increased utilization of energy efficiency and conservation measures and/or

increased load shifting, either through demand side management projects, i.e., automated

controls, thermal energy storage, or through customers changing the operational hours of their


equipment. This in turn works to decrease EPE's summer peak, which can help reduce the need

for or delay new capacity resource additions.

DRPP

In Case No. 15-00127-UT, EPE proposed an RFP process to initiate a pilot program to gauge the

acceptance and efficacy of demand response utilizing programmable or "smart" thermostats to

target air conditioning load. Demand Response is a proposed voluntary program that engages

utility customers to reduce their electricity use (load) during peak hours or under certain

conditions. Peak electricity demand typically occurs on hot summer days when households turn

on their air conditioning (“A/C”). Fundamentally, the main goal of the demand response

program is to reduce A/C usage on hot summer days, which in turn, can reduce demand for

electricity during peak hours, providing aggregate benefits for the electric grid and households

themselves. Following approval by the Commission for EPE’s proposal, EPE conducted an

RFP, selected a vendor and implemented a 3-year pilot prior to the summer period of 2017.

Load curtailment in the DRPP is accomplished through a combination of continuous monitoring

and adjustment of thermostats during the cooling season as well as more dramatic adjustments

for short intervals as targeted curtailments. EPE separately meters and analyzes demand response

by a sample of participants to measure load reductions and validate data reports provided by the

third-party vendor. If the data supports energy efficiency cost effectiveness requirements, EPE

could propose such a program as part of an energy efficiency measure or program at the

conclusion of the 3-year pilot.


Customer and System Benefits

TOU and other variable pricing and dynamic pricing options provide customers the opportunity

to impact their monthly bill by modifying energy consumption in response to price differentials.

In the simplest case, this means adjusting usage (energy consumption) during different times of

the day, by either reducing consumption or shifting usage to a lower-priced period. The extent to

which a customer may benefit is a function of the price of energy in the standard offering, the

price differentials offered in the optional pricing structure and the customer’s ability to manage

their energy consumption. A marginally higher on-peak price, for example, provides a greater

incentive to reduce consumption than the lower standard price for consumption in the same

period. Likewise, a shifting of consumption from high-price to low-price periods is incentivized

by the price differential by providing a benefit not available under a level price standard rate.

Dynamic pricing options, which can be constructed as overlays to either a standard or TOU

pricing option, can increase customer benefit.

Another fundamental variable in the ability of price response rates to impact customer usage and

system load profile is whether the rate structures are voluntary or mandatory. Customer “opt-in”

performance, where customers make an affirmative decision to participate in a voluntary pricing

program with both potential risk and benefit is typically low, and utility efforts to generate

customer participation constitute an additional cost for programs. Generally speaking, voluntary

participation programs consist largely of functional benefiters – customers receiving rate benefit

due to the nature of their usage profile with little or no change in their consumption


characteristics. Conversely, mandatory TOU rate structures, such as EPE currently provides for

its largest commercial and industrial customers have 100% participation rates, with resulting

customer and system benefits a function of the ability of customers to adjust their usage profiles

over the long-term.

Dynamic pricing programs generally overlay standard or voluntary pricing options. Critical Peak

Pricing (“CPP”), Peak Time Rebate (“PTR”) and Capacity Bidding are examples of dynamic

pricing programs which can overlay mandatory rate structures and require advanced metering

capability. All are callable programs which can be initiated on day-ahead or even day-of notice

to achieve demand reductions during peak periods. Dynamic pricing as an overlay to a TOU

pricing option offers EPE the ability to offer additional savings, based on a near-term need for

resources, over and above what can be achieved through peak rate differentials. For example, a

PTR option can provide incremental reductions in on-peak usage already reduced in response to

TOU pricing differentials, which benefits both the participating customer and the utility.

EPE’s 20-Year Rate Initiative

The EPE system load profile is one cost-driver of overall rate levels. The system profile in turn

is impacted in the long-term by both permanent changes in customer consumption and short-term

response to rate differentials. Permanent changes in customer usage profiles result from long-

term exposure to predictable price differentials, and are most directly impacted by mandatory

rate structures. Residential, commercial and industrial customers require time to adjust their

usage characteristics in response to pricing differentials, and pricing differentials based on cost


of service generally change slowly. Dynamic pricing options in contrast are intended as short-

term resource options for the utility. The combination of the two pricing approaches can, over

the long-term, impact the system profile sufficient to impact resource planning.

The table below shows a long-term plan for rate structure development focused on providing

customers increasing levels of price information and menu of rate options, and designed to

provide customers the opportunity to benefit from changes in their usage characteristics.

Table 15 - Rate Structure Development

Current 3-Year 5-Year 10-Year 20-Year Residential

Energy Energy Energy / CPP & PTR

Energy / CPP & PTR

TOU Energy /

CPP & PTR Small Commercial

Demand / Energy

Demand / Energy

Demand / Energy

CPP & PTR

Demand / TOU Energy CPP & PTR


Medium Commercial

Demand / Energy

Demand / TOU Energy




Industrial and Military

Demand / TOU Energy

Demand / TOU Energy

TOU Demand /

TOU Energy

TOU Demand /

TOU Energy Capacity Bidding

TOU Demand /

TOU Energy Capacity Bidding

Irrigation and Pumping

Demand / TOU Energy

Demand / TOU Energy

Demand / TOU Energy

Demand / TOU Energy

Demand / TOU Energy

The solid black line indicates the point at which the mandatory rate structure for the class would

include TOU energy charges (the TOU line). Generally, large industrial, military, and irrigation


and pumping customers already have mandatory TOU pricing tariffs. The vertical double-line

indicates approximate timing for completion of a system-wide Advanced Metering Initiative

(“AMI”). Because of the number of customer accounts represented by the Residential and Small

Commercial classes, advanced metering on a system-wide basis is critical to the success of

expanding TOU and dynamic pricing options.

Advanced Metering Initiatives (AMI) and Customer Options

System-wide advanced metering enables the maximum availability of pricing options and

customer programs designed to provide benefits to customers and the overall system. For

purposes of this discussion system-wide “advanced metering” means retail metering capable of

providing interval metering data accessible to EPE for analysis and billing purposes on at least a

monthly basis, and the data processing systems capable of managing the data and computing

bills under complicated pricing programs. Implicit in this definition is EPE’s ability to access

and process data on an accelerated basis; from acquiring the data from meters, communicating

that data to databases, and accessing the data for analysis and billing purposes.

VII. DESCRIPTION OF THE RESOURCE AND FUEL DIVERSITY

EPE primarily meets its customers' electrical demands with power generated from its generating

stations, which are powered by natural gas and uranium. Utilizing renewable resources,

particularly solar, as part of its system, EPE increases its fuel resource diversity. While EPE no


longer has the coal-fired FCPP in its resource fleet, EPE is still able to maintain a diverse

resource mix of nuclear, gas-fired, renewables, and purchased power.

EPE's energy mix for 2017, the most recently completed calendar year, is based on MWh

generation as shown in Figure 5 below:

Figure 5 - EPE 2017 Energy Fuel Mix

VIII. IDENTIFICATION OF CRITICAL FACILITIES SUSCEPTIBLE TO SUPPLY-

SOURCE OR OTHER FAILURES

EPE’s current critical facilities that are susceptible to supply-source or similar failures include its

natural gas fired generation plants. These facilities are susceptible to supply-source failures due

to the fuel required for unit operation and the resulting power generation. If the natural gas

NUCLEAR 48.7%

NATURAL GAS 36.6%

PURCHASE POWER 11.9%

RENEWABLE 2.8%

EL PASO ELECTRIC FUEL MIX


supply-source was to experience a large scale failure, then some of EPE’s critical facilities could

be impacted. To mitigate some of this risk, EPE periodically reviews its natural gas

transportation and storage capability and any local fuel related concerns. EPE is connected to

two major gas pipelines (each with multiple large lines entering the city) on the interstate and on

the intrastate system. EPE also has emergency on-site fuel oil backup capability at both of its

largest local generating facilities, i.e., Newman and Montana. This multiple gas pipeline

configuration, as well as purchased power availability as transmission constraints permits, fuel

oil backup, and EPE’s ability to activate the HVDC Eddy Tie which is interconnected to the SPP,

would contribute to EPE’s ability to mitigate local fuel and service requirements given a supply-

source failure at a critical facility. In addition, EPE has nuclear units that would not be impacted

by a gas pipeline outage.

EPE’s existing solar resources are also susceptible to "supply disruptions" given their

dependency on solar irradiance. EPE’s existing solar nameplate capacity of 115 MW (including

the 5 MW Holloman project) does not present an energy supply risk. However, consideration

would need to be given for additional amounts of solar and wind, see Section IX.

IX. DETERMINATION OF THE MOST COST EFFECTIVE RESOURCE PORTFOLIO

AND ALTERNATIVE PORTFOLIOS

EPE has considered all feasible supply, energy storage, and demand-side resource options on a

consistent and comparable basis in order to develop the optimal resource portfolio. Given the


added complexities and characteristics of today’s resource options, it is necessary to describe the

planning analysis.

Ultimately, the goal is to ensure that EPE has a portfolio that reliably meets both the peak and

energy demands of our customers. Given this goal, it is necessary to analyze what combination

of resources, given their respective characteristics, can optimally serve load. EPE utilized a

capacity expansion model, Strategist, to perform the analysis.

Strategist

Strategist is a resource expansion planning software application to develop the model that

determines the optimal integrated demand-side and supply-side portfolio for a utility system

under a prescribed set of inputs and assumptions. Strategist enables EPE to study a wide variety

of long-term expansion planning resource options and their costs (described in Section VI), unit

retirements, unit capacity variations, demand-side management options, fuel costs, and reliability

limits in order to develop a coordinated integrated plan which would be best suited for the EPE

system. Strategist simulates the operation of a utility system to determine the cost and reliability

effects of adding various resources to the system or modifying the load through marketing or

conservation programs. Strategist is also equipped with tools to facilitate the screening of

individual alternatives and how they interact with the EPE system. In addition, Strategist can

assess the impacts of various scenarios and sensitivities based on total plan costs.

Resource options are ranked by Strategist based on their individual economic impact on the EPE

system. For each resource option, EPE's net present value of revenue requirements over the


entire planning period, in this case 2018 through 2037, is calculated. Strategist will optimize the

resource mix to meet reserve requirements and reliability constraints over the Planning Horizon.

The present value of revenue requirements (in Strategist known as the Present Value of Utility

Cost) for each plan is evaluated over the Planning Horizon and then ranked against the other

plans. This procedure identifies the most cost-effective resource portfolio that provides optimal

interactions with the EPE system model in Strategist.

In addition to the key inputs that were defined above for Strategist, there are other resource-

specific inputs that are required to correctly capture characteristics inherent to certain

technologies which are described below.

Solar

Solar facilities have operating and load serving characteristics that were evaluated by EPE to be

properly considered by the model. It is worth noting that solar contributes 25% of nameplate

capacity to serving peak load. In fact, in EPE’s 2015 and earlier IRPs, solar was credited with a

70% of nameplate capacity for contribution to peak.

As is the norm in the industry, the output profile of solar can be viewed as a reduction to load.

The resulting difference between load and solar output is referred to as the net load. Given the

output profile correlating to sunlight hours, the net load (i.e. reduction of load) only occurs

during sunlight hours, and therefore does not reduce load in the hour following sunset. At a

certain inflection point, solar resources do not contribute to serving this new net peak load hour,


as is illustrated in Figure 6. Given EPE’s peak load profile, the inflection point occurs at a total

of 400 MW of solar resources. The net load at 400 MW is 1,884 MW versus the new evening

peak load of 1,886 MW. While the additional solar above the 400 MW will offset energy, it

does not contribute to serve the new evening peak. Solar would only be able to serve the new

evening peak if coupled with energy storage such as batteries.

Figure 6 - Duck Curve at Various Solar Integration Levels


Additionally, there is a difference between the expected output profile of solar and its

contribution to meeting peak load from a resource planning perspective. As previously

mentioned, solar output is variable and in turn introduces the risk of output levels below

expected output. Given EPE’s existing installed solar capacity, the risk of reduced output has

been minimal given EPE’s current solar capacity. Previously, EPE credited solar contribution to

peak at 70%, which is equal to its expected output. With 107 MW of installed solar, EPE

credited 74 MW to serving peak load; however, in 2016, EPE registered solar output in the

29 MW range on the second highest peak load day for 2016. While the 48 MW deficiency was

manageable, a greater number of solar installations would result in a proportional deficiency and

increase the magnitude of that deficiency. For example, if the solar installation were 400 MW,

the proportional deficiency on a comparable day would have been 179 MW. Therefore, it is

necessary to adjust the contribution to peak from solar facilities. The analysis indicates 25% of

nameplate capacity is an appropriate contribution to peak with a 95% confidence. The 25%

contribution to peak would apply to the first 400 MW of installed solar (inclusive of the 110 MW

already installed). It is important to note that the energy profile is modeled to the expected

levels, in this manner solar resources are credited for their energy contribution. Any solar

considered above the 400 MW level would not contribute to the new evening peak unless it is

coupled with energy storage. Therefore, solar above the 400 MW is credited with zero

contribution peak.


Wind

Wind resources also have unique characteristics. First, its output profile is a lot less consistent

and highly variable when compared to solar. Wind output profiles are typically provided based

on expected (average) profiles for each month. However, it is difficult to credit wind with any

significant contribution to peak because of its day-to-day variability. Figure 7 illustrates

expected monthly output profiles for wind resource regions that are closest to EPE’s service

territory. The present profiles demonstrate two important characteristics. First, the months of

May to August, which are EPE’s peak months, have the lowest average output profiles. Second,

during EPE’s peak hours, wind output is at their lowest. While wind has come down

significantly in cost, it does not offer firm output for meeting peak load. More appropriately,

wind may be evaluated as potential fuel savings if its costs are sufficiently low. EPE modeled

wind with its respective output profiles, with a zero contribution to peak. The output energy

profile allows for consideration of potential fuel savings. Wind, much like solar, may offer peak

contribution if coupled with energy storage, and this type of option was modeled in Strategist.


Figure 7 - Monthly Wind Profiles Storage

Storage is modeled as a lithium ion battery storage system. The standalone storage system is

modeled with a dispatch that assumes charging in the early morning hours when system load is at

its lowest and system cost are expected to be lower. Storage coupled with solar is assumed to be

charged beginning at sunrise, and storage coupled with wind is assumed to be charged

throughout the night. As previously mentioned, these storage systems typically have an 80%

efficiency and are subject to constraints in Section VI. Accordingly, the dispatch profile assumes

a longer charging period to incorporate the efficiency.

Retirement Analysis


Pursuant to the Stipulation Agreement, EPE analyzed any retirements planned within the first

five years of the Planning Horizon. This analysis applies to Rio Grande Unit 66 which has a

planned retirement of 2018 as well as Rio Grande Unit 7, Newman Unit 1, and Newman Unit 2

for this IRP, as they are planned to retire in 2022. In order to facilitate this evaluation, EPE hired

the services of Burns and McDonnell to assess the conditions of the units and estimate of

investment and operating costs to ensure safe and reliable energy for two time frames, through

2027 and 2037. The retirement analysis was performed in Strategist where the unit extensions

were introduced as options competing against the IRP resource options as part of the Base Case.

The respective capital and projected O&M expenditures were utilized for each option.

A. Most cost effective portfolio (Base Case)

Base Case

The Base Case Portfolio was developed utilizing the planned retirements as defined in Table 2.

The Base Case utilized the most likely expected values for inputs and provides the most cost

effective portfolio. All other inputs utilized are as described in the preceding sections. The

resulting portfolio is as follows:

6 As ordered in Case No. 17-00317-UT, Rio Grande 6 was also analyzed.


Table 16 - Base Case Portfolio


2018 2019 2020 2021

Solar PV 25 6.25

2022

Solar PV 75 18.75 Solar PV 75 18.75 Solar PV 75 18.75 Solar PV 100 25 Battery Storage 15 15

2023 Combined-Cycle 320 320 2024 2025 2026

2027


2028 Combustion Turbine 100 100 2029 2030 2031 Combined-Cycle 320 320 2032 2033




2037 Biofuel 20 20


The resulting nameplate resource mix at year 2023 (the next major resource addition year)

is:

Table 17 - Base Case Portfolio Nameplate Mix

Nameplate MW

Percent by Nameplate

Contribution to Peak

Percent by Contribution

to Peak Solar 465 17% 168 7% Gas 1,570 58% 1,570 65% Nuclear 633 23% 633 26% Storage 15 1% 15 1% Emerging Tech 40 1% 40 1%

Mitigating Ratepayer Risk

Risk mitigation for resource selection is achieved in several ways. First, EPE incorporates risk

variables for reliability, operational considerations, fuel supply and price volatility and

anticipated environmental regulation in its analysis of competing resource options. EPE also

analyzes sensitivities in resource selection for variations in forecasted load over time. Finally,

because ultimate resource additions can take a considerable amount of time, ratepayer risk

mitigation is achieved by constantly updating underlying assumptions as to capacity needs and

timing of resource additions.


B. Considerations – Reliability

The most cost effective portfolio takes into consideration cost, reliability, safety,

environmental, and operating characteristics. It reliably introduces a significant

amount of solar renewable energy while addressing the intermittency characteristics

of solar. Additionally, it selects solar coupled with battery storage which again

allows the addition of solar while providing firm output characteristics during peak

hours with the battery storage. Gas generation is also selected to provide firm

resources for peak hours.

Throughout the 2018 IRP, EPE accounted for transmission and reserve margin

constraints in order to capture these parameters while considering total electric

system reliability. Each resource analyzed as a portfolio option on a cost-effective

basis must also demonstrate its ability to sustain and complement overall system

reliability. EPE took into account its geographical location and its transmission

import limits when developing its optimal portfolio. The resulting portfolio ensures

an adequate reserve margin that is consistent with EPE’s prior IRPs.

As stated above, energy efficiency and load management programs were taken into

consideration during the IRP, both as a forecasted reduction in load and as a resource

option. DR programs and EE are shown in the L&R in Section 4.0. EE resources

were considered above the EUEA requirements. The resulting IRP portfolio

determined that additional DR and EE currently need not be part of the optimal


portfolio above and beyond the EUEA and forecasted DR. Based on the input

assumptions for these resource options, the IRP analysis model did not find that the

addition of these resources when paired with other resource options would result in

the optimal portfolio. This is likely due to the relatively low contribution to peak

capacity need and the acceptance rate of this type of resource by EPE customers.

EPE’s current generating portfolio provides for minimal exposure to the EPA’s

guidelines to reduce carbon dioxide emissions. Moving forward, the Plan illustrates

that EPE will continue to improve environmental stewardship due to the increased

percentage of renewable resources in EPE’s optimal portfolio. The inclusion of

renewable resources above regulatory requirements demonstrates EPE’s efforts to

limit its carbon footprint.

Given the increased amount of renewables and the introduction of battery storage, the

cost effective portfolio has a greater diversity of resources.

C. Alternative portfolios (sensitivities, carbon tax)

Sensitivity Analysis

EPE analyzed various sensitivities to capture the cost differences and changes to the

resource expansion plan. The sensitivities included variations to projected load, forecasted

natural gas prices, and carbon tax costs at different price thresholds. Therefore, EPE


modeled and analyzed high and low sensitivities on load, natural gas prices, and low, mid

and high carbon tax. Results from the Strategist sensitivities are presented in Section IX,

which include the present value utility costs for each plan.

Load Sensitivity Analysis

For EPE's High and Low Load sensitivities, EPE analyzed its 2018 Load Forecast to reflect

economic recovery and a more robust economy (increases in customers and businesses) by

utilizing the high bound of the 2018 Load Forecast. EPE then analyzed the lower bound of

its 2018 Load Forecast to represent a decline of the economy (e.g., closure of businesses,

loss of customers and military troops projected to be transferred to the El Paso area).

Tables 18 and 19 show the load sensitivity results.

In the Low Load Case, less generation capacity was needed upfront, therefore the first

generation capacity addition was pushed back from 2022 in the Base Case to 2023 in the

Low Load case. In the Low Load Case, solar PV was reduced from 350MW added in 2022

in the Base Case to 250 MW added in 2023 in the Low Load case. Also, for the Low Load

Case, the 320MW combined cycle that was added in 2023 in the Base Case was replaced

with a 100MW combustion turbine in the Low Load Case. Further, 100 MW of battery

was added in the Low Load Case as compared to 15MW of battery storage in the Base

Case. Hence, in the Low Load Case, the amount of generation capacity needed to meet

EPE’s load was reduced in conjunction with the decrease in load.


In the High Load Case, additional generation capacity was needed upfront in 2022. The

additional generation capacity need in the High Load Case was met by adding a 100MW

combustion turbine and additional battery storage. Battery storage increased from 15MW

in the Base Case to 80MW in the high load case. A 320MW combined cycle was added in

2023 for both, the High Load Case and Base Case. The Solar PV capacity decreased from

350MW in the Base Case to 275 MW in the High Load Case.

Hence, in the High Load Case, the generation capacity needed to meet EPE’s load

increased in conjunction with the increase in load. The increased need in generation

capacity was met by adding more natural gas generation and battery storage.


Table 18 - Low Load Sensitivity


2018 2019 2020 2021 2022

2023

Solar PV 75 18.75 Solar PV 75 18.75 Solar PV 100 25 Combustion Turbine 100 100 Battery Storage 50 50

2024 Battery Storage 50 50 2025 2026 2027 Combined-Cycle 320 320

2028 Solar PV & Battery 100 25 30 30

2029 2030 2031 Combined-Cycle 320 320 2032

2033

2034

Combustion Turbine 100 100 Reciprocating Engine 50 50

Solar PV & Battery 100 0 30 30

2035 Reciprocating Engine 50 50


2037 Biofuel 20 20


Table 19 - High Load Sensitivity


2018 2019 2020 2021

2022

Solar PV 75 18.75 Solar PV 100 25 Combustion Turbine 100 100 Battery Storage 50 50


2023 Combined-Cycle 320 320 2024 2025 2026 2027 Combined-Cycle 320 320 2028 Combustion Turbine 100 100 2029 2030

2031

Combustion Turbine 100 100 Reciprocating Engine 50 50 Battery Storage 50 50

2032 Biofuel 20 20


2034 Combined-Cycle 320 320 2035 2036 2037 Geothermal 20 20


Fuel Cost

On the high and low natural gas price sensitivities, EPE analyzed a 15 percent price

increase and a 15 percent decrease, respectively.

The Low Fuel Cost sensitivity case resulted in 325MW of solar PV added in 2022 in the

Low Fuel Cost Case as compared to 350MW of solar PV added in the Base Case. Also,

15MW more battery storage was added in 2022 in the Low Fuel Cost Case. The 320MW

combined cycle was added in 2023 for both, the Low Fuel Cost case and the Base Case. A

lower fuel price makes natural gas generation more economical and thus, less solar was

added upfront in the Low Fuel Cost Case.

For the High Fuel sensitivity case, the resulting resource expansion plan was unchanged

from the Base Case expansion plan for 2022 and 2023. The only change that occurred was

in 2027 where two 50MW reciprocating engine resources in the High Fuel Case replaced a

single 100MW reciprocating engine resource.


Table 20 - Low Fuel Cost Sensitivity


2018 2019 2020 2021

2022

Solar PV 75 18.75 Solar PV 75 18.75 Solar PV 75 18.75


2023 Combined-Cycle 320 320 2024 2025 2026 2027 Combined-Cycle 320 320 2028 Combustion Turbine 100 100 2029 2030

2031 Combustion Turbine 100 100 Battery Storage 50 50 Battery Storage 50 50

2032



2035


2037 Biofuel 20 20 Geothermal 20 20


Table 21 - High Fuel Cost Sensitivity


2018 2019 2020 2021

2022

Solar PV 25 6.25 Solar PV 75 18.75 Solar PV 75 18.75 Solar PV 75 18.75 Solar PV 100 25 Battery Storage 15 15

2023 Combined Cycle 320 320 2024 2025 2026

2027

Solar PV 100 25 Combustion Turbine 100 100 Reciprocating Engine 50 50 Reciprocating Engine 50 50 Battery Storage 50 50

2028 Combustion Turbine 100 100 2029 2030 2031 Combined Cycle 320 320 2032 2033




2037 Biofuel 20 20


Carbon Tax

EPE used the carbon tax price thresholds as defined in Case No. 06-00448-UT of $8, $20 and

$40 escalated at 2.5% annually from 2011. EPE used the $0 carbon tax price as part of its Base

Case, with the $8 and $40 sensitivities representing the lower and upper bounds of the carbon

tax. Since EPE’s resource plan doesn’t consist of any coal units, the effect of a carbon tax is

minimized. As shown in TABLE 22-24 below, there were no major changes to the Carbon

sensitivity cases as compared to the Base Case.


Table 22 - $8 Carbon Tax Sensitivity


2018 2019 2020 2021

2022


2023 Combined Cycle 320 320 2024 2025 2026

2027



2034

Combustion Turbine 100 100 Reciprocating Engine 100 100


2036 Battery Storage 50 50 2037 Biofuel 20 20




2018 2019 2020 2021

2022


2023 Combined Cycle 320 320 2024 2025 2026

2027









2018 2019 2020 2021

2022


2023 Combined Cycle 320 320 2024 2025 2026

2027







No Combined Cycle

Based on a request from the New Mexico PAG, EPE ran a sensitivity in which the 320MW

combined cycle generation resource was taken out of the optimization run for the 2022-

2023 time period. The No Combined Cycle sensitivity case resulted in the selection of the

15 year 74MW Newman Unit1 Extension, 15 year 46MW Rio Grande Unit7 Extension,

and 100MW combustion turbine along with 50MW of battery storage being added in 2023.


Table 25 – No Combined Cycle Sensitivity


2018 2019 2020 2021

2022


2023

Newman 1 Extension 74 74 Rio Grande 7 Extension 46 46 Combustion Turbine 100 100 Battery Storage 50 50

2024 2025 2026 2027 Combined Cycle 320 320

2028

Combustion Turbine 100 100 Reciprocating Engine 100 100 Battery Storage 15 15

2029 2030 2031 Combined Cycle 320 320 2032 2033




2037 Biofuel 20 20 Geothermal 20 20


D. Recommended Portfolio

The IRP provided a comprehensive review of EPE’s resource needs and options for the

Planning Horizon. It included considerations of costs, reliability, safety, operating

characteristics, environmental, and risks resulting in the recommendation of the optimal

portfolio. As a result, EPE’s recommends the Base Case resource plan, as set forth in the

following Table 25.

It is noted that the actual resource additions in the future will be determined by results of

competitive requests for proposals and may differ based on future forecasted loads,

economic conditions, technological advances, specific generation resource proposals, and

environmental and regulatory standards. The Planning Process utilized publicly available

information to analyze resource options.


Table 26 - L&R Most Cost Effective Portfolio


X. DESCRIPTION OF PUBLIC PROCESS

A. Overview of the Public Process

The purpose of the Public Process is for the utility to provide information to, and receive

and consider input from, the public regarding the development of its IRP (17.7.3.9.H

NMAC).

EPE encouraged public involvement in its Public Process and hosted a total of 17 public

advisory meetings over the course of approximately sixteen months. During the public

meetings, EPE presented information and material on its Planning Process by Company

subject matter experts and EPE also received feedback from the Participants. On several

occasions, Participants presented their own information and material for consideration by

EPE and other members of the public. EPE, with direct assistance from the Commission

Staff-selected facilitator, Myra Segal (the “Facilitator”) structured the Public Process to be

an inclusive and interactive manner. Participants were able to attend in person, call into the

meetings, or participate remotely through web-based meetings using Skype for Business

("Skype"). The Skype meetings were set up so that the PAG could view presentation

materials taking place during each meeting and hear audio. These remote Participants were

able to submit questions through the Skype conversation panel.


EPE recorded the meetings and posted each recording on EPE’s IRP website. This

additional feature allowed Participants to go back at any time to a meeting they may have

missed or wanted to hear again.

The Facilitator communicated between EPE and the PAG so that all feedback was

communicated clearly to EPE and responded to in a timely manner by EPE. Ms. Segal also

coordinated the dispute resolution process discussed below in accordance with the Rule.

Additional discussion and feedback also took place outside of scheduled meetings. The

Participants submitted questions, requests, articles, and essays for consideration by EPE

and other members of the public. EPE responded to all written requests for information in

writing as described in the Stipulation Agreement. In total, EPE and the PAG developed

over 60 pages of written requests for information and responses.

By attending any public meeting, the Participants were automatically enrolled in EPE’s

PAG list, where they were notified of upcoming meeting information, new website

material, written questions and responses, and other IRP updates. Another available

resource for the PAG was EPE’s IRP website which includes helpful information and

resources, such as IRP presentation material, written questions and responses, meeting

schedule information, remote participation information, past IRP information, and rules and

statutes information.

The sections below will describe the Public Process in more detail.


B. Notice and Public Outreach

EPE initiated the Public Process by publishing notice in the Las Cruces Sun-News, a

newspaper of general circulation in every New Mexico County in which EPE serves,

30 days prior to the first scheduled meeting, which was May 25, 2017. EPE also included

notice of the PAG meetings in New Mexico customer bill inserts. Additionally, EPE

provided notice 30 days prior to the first scheduled meeting to the Commission,

intervenors in its most recent general rate case, intervenors in its most recent renewable

energy procurement case at the time, and intervenors in its most recent energy efficiency

case. The notice and certificates of service were filed with the Commission's Records

Bureau. EPE also posted a notice on the home page banner of its website. The notice has

stayed on the home page of EPE’s website for the entire duration of the Public Process. In

June 2017, EPE sent an additional notice to its New Mexico customers via EPE’s

Connections newsletter included in monthly bills as a reminder that the meetings had

started.

C. Attendance

Approximately 60 people attended EPE’s public advisory meetings, either remotely or in

person, over the course of the approximately 16-month Public Process. The average

in-person participation was 10 people. The average Skype participation was 4 people.


Public participation consisted of continuous attendance from a small group of participants

who were very active and engaged throughout the entire Public Process. These Participants

submitted the vast majority of written questions and requests, submitted resource input

templates with sources, participated in the dispute resolution process, attended most

meetings, and some presented their own material as well. There were other Participants

who attended less frequently but also contributed to discussion and brought their own

issues to the public meetings. These Participants tended to be more interested in DG rates.

There were also representatives from certain groups and companies, such as Coalition for

Clean Affordable Energy, First Solar, Positive Energy Solar, Western EIM, City of

Las Cruces, and others. NMPRC Staff was represented at each meeting.

Participants demonstrated interest and a disparate level of understanding of the Planning

Process, and an appreciation, to some degree, of the complexity involved.

D. Meeting Schedule and Format

EPE’s original public advisory meeting schedule included 14 meetings; but, with the

addition of three meetings requested by public participants, the final schedule consisted of

17 meetings. EPE modified its initial meeting schedules to accommodate several requests

of the PAG. For example, EPE re-organized or postponed scheduled topics to be covered to

accommodate increased time dedicated for requested public discussion. EPE included two

meetings at the NMPRC offices in Santa Fe in order to facilitate direct NMPRC Staff


participation in the Public Process. Attachment A shows the original and final public

advisory group meeting schedule.

Meetings were typically held on Thursday’s at 2 pm, for the duration of 2.5 hours. In EPE’s

experience, meetings held outside of normal business hours did not increase public

participation. In addition, EPE received largely positive feedback from the PAG regarding

the 2 pm meeting time. All meetings were at the Doña Ana County Government Center,

except the first meeting and the two meetings held at the NMPRC offices. This new venue

received positive reviews from the PAG. It provided ample parking space, was easily

accessible, and is a well-known location in Las Cruces.

EPE had originally scheduled two meetings where the PAG members could present their

own material and get EPE feedback in January and February 2018. In response to public

feedback, EPE added two additional meetings of this type; first on September 22, 2017, and

second on October 20, 2017. EPE also added a meeting on plant retirements as a result of

public interest on the topic. This resulted in 3 additional public meetings, for a total of five

public meetings to specifically address issued raised by the Participants, which are shown

in Attachment A-2.

EPE presented topics required in the Rule for the Public Process (see Attachment A-1), as

well as more detailed information on those topics in order to better inform the Participants

on the issues addressed in the IRP. These detailed topics were covered at the beginning of


the Public Process so that more time could be dedicated to the development of the most

cost effective portfolio and review of the IRP report.

During the October 5, 2017, meeting, EPE went into more detail on the modeling process

and assumptions. During this time, the Participants were encouraged to submit Resource

Input Templates, which were developed by EPE as a result of public interest in proposing

resource types with specific costs and production characteristics. More information on the

Resource Input Templates is found in the Public Input section below.

The remainder of the meetings consisted of more detailed discussion of the IRP modeling

processes and evaluation of the most cost effective portfolio. The schedule was structured

so as to cover the required data as quickly and fully as possible to allow more time for

development of the cost effective portfolio. EPE has learned from past IRPs that

Participants tend to be more focused on this portion of the IRP public process.

The structure of the PAG meetings varied. Some meetings were "open discussion" where

EPE had some presentation material and discussion was allowed throughout. Other

meetings had designated discussion periods, while other meetings consisted of the PAG

presenting material and EPE providing feedback.


E. Public Input

EPE structured the Public Process to solicit, receive and consider public comment

regarding the development of its IRP in a number of ways. EPE encouraged Participants to:

• attend public advisory meetings in person and give their input during the meetings,

• submit written notecard requests for information in person; during the meetings,

• send EPE their written input or requests by email, during or after scheduled meeting,

• fill out and submit feedback forms via written and/or phone, and,

• fill out and submit Resource Input Templates if they wanted EPE to consider a specific

resource type.

In total, EPE received over 202 individual written questions, totaling 73 pages of questions

and responses.

The Resource Input Templates were developed as a result of public interest in proposing

resource types with specific costs and characteristics. In response to this interest, EPE

developed a template form for the PAG to complete, so that EPE could receive and

consider public requests for specific resource types, in an organized and efficient manner in

developing its IRP. EPE requested background and source documents to be submitted with

templates if utilized. In total, EPE evaluated 16 Resource Input Templates and provided

responses to each of these. An explanation was given as to whether the resource proposal

was a feasible option or not. Attachment A-5 was provided to Participants during the


October 5, 2018, meeting as an example of what a filled in template looks like, and the

template for was posted on EPE’s IRP webpage.

EPE received and considered all views and opinions expressed during the Public Process.

Some of the most prominent themes expressed by Participants included:

• the incorporation of an increased amount, and in some cases up to 100%, of renewable

and battery storage resources into the IRP resource portfolio,

• the incorporation of an increased amount of energy efficiency initiatives and demand

response option into the IRP portfolio,

• L&R: increase energy efficiency and DG forecasts, reconsider retirement dates, and

increase amount of renewables,

• rates: increase TOU price differentials and other rate changes in order to influence load,

• interest in Strategist, modeling inputs, and resource cost assumptions,

• interest in removing nuclear energy from the resource portfolio, and,

• interest in off-system sales.

All of these opinions were expressed during public advisory meetings as well as in writing.

A complete list of the written questions and requests from Participants with EPE’s

responses can be found on EPE’s IRP webpage,

https://www.epelectric.com/community/2017-18-public-advisory-group-meetings

https://www.epelectric.com/community/2017-18-public-advisory-group-meetings


The feedback forms are also a source of insight into input EPE solicited, received and

considered from the PAG. These are summarized in Attachment A-4.

Below is a list of specific PAG input that EPE agreed to incorporate in the development of

the most cost effective portfolio for its IRP:

• create a portfolio for analysis that is heavily renewable favored,

• conduct a second Strategist run excluding the first selected resource from the base case

and compare the results,

• identify and evaluate solar, wind and storage options with declining costs drops for

assets to be added in the 2021-2023 timeframe for use in the model,

• introduce a resource option of solar coupled with storage,

• use an independent evaluator to verify that the resource prices between EPE’s RFP and

IRP are consistent,

• include a discussion on T&D costs through locational resources, and

• have its consultant Burns &McDonnell perform an analysis of generation unit

retirements using shorter intervals than originally planned.

In accordance with the recent Rule Amendment, the public will be able to file written

comments after EPE files the IRP. EPE is required to file a written response.


F. Facilitator

EPE was assisted in the Public Process by a Commission Staff-selected facilitator, Myra

Segal, who was recommended by a few public advisory participants.

Over time, the Facilitator’s role adapted to the changing dynamic of the public advisory

process. During the first few meetings, she observed, took notes on follow-up items, and

solicited initial feedback from the public via a July feedback form she created and

distributed. During subsequent meetings, the Facilitator assisted with the organization and

the flow of the meetings. The Facilitator supported EPE’s decision to designate discussion

periods following presentations for the purpose of limiting interruptions of presentations,

so that presenters could convey information within the time constraints of the scheduled

meetings. During the later meetings, Ms. Segal assumed a more active role of guiding

public advisory group discussions asking questions throughout the meetings, making

clarifications, and adding her input. She also was better able to manage discussion time.

In order to promote discussion within the public advisory process, EPE adopted several

suggestions from the Facilitator. One of the recommendations that EPE adopted was to

form the tables into a "U"-shape in order to promote discussion. The group dynamic

became more conversational as a result, and EPE received positive feedback on this

change.


The Facilitator distributed two feedback forms, one in July 2017, and another in October

2017. A summary of the results are shown in Attachment A-4.

1. Dispute Resolution

Another key role of the Facilitator is dispute resolution, as described in the IRP

Rule (17.7.3.9.H.2).

The Facilitator developed a process for dispute resolution that included a written

request from the Participant seeking dispute resolution, an EPE response, an

evaluation using a dispute resolution matrix, and hosting web meetings as necessary

for discussion. The Facilitator documented the dispute, communications, and

outcome of each dispute. In total, there were 6 disputes sent to the facilitator by the

PAG. A summary of each dispute is provided below:

1. RFP Bids

"I am asking that the information on resource options represented by the

proposals available since October 4, 2017, from the all-source RFP be included

in the analysis for constructing El Paso Electric’s 2018 Integrated Resource

Plan."


EPE Compromise: Use an Independent Evaluator to confirm that resource

prices used in Strategist are consistent with RFP resource prices.

Outcome: In progress: Compromise resolution submitted by EPE, awaiting best

and final RFP bid package for Independent Evaluator assessment and affidavit.

2. Distribution Plan

"I am requesting the Distribution Expansion plan referenced below the legend

on the second map page of EPE's 10-year transmission plan."

EPE Compromise: EPE will include in its IRP Report a discussion on T&D

costs through locational resources.

Outcome: In progress; EPE to evaluate how avoided T&D costs may be

attributed to locational resources modeled in Strategist. EPE will identify any

publicly available data on distribution capital investment projects.

3. Retirements

"I am asking that EPE evaluate the continued operation of units slated for

retirement within five years on a consistent and comparable basis with other

resource options. I believe that means evaluating the option of life extension on


a year-by year basis until and unless it is established that a one year life

extension is not feasible. If there are costs for maintenance, repair, or retrofit

they should appropriately be included in the analysis and evaluated within

Strategist just as all other resource options, existing or potentially new

additions, are evaluated."

EPE Compromise: Burns &McDonnell will do a 5 year assessment (2027,

which is 5 years after scheduled retirement) and 15 year assessment (2037) for

evaluation on retirement of units.

Outcome: In progress; EPE to respond on whether or not shorter time intervals

(e.g., 1-year, 3-year, 5-year, 10-year) will be assessed by the contracted firm

(Burns & McDonnell) along with its planned 20-year retirement assessment.

4. DG as a Resource

"I am asking that EPE evaluate Distributed Generation as a resource option. I

am proposing that for $20/MWh an additional 5 MW of usable capacity at peak

per year every year can be added to the system over and above the current

assumptions built into the forecast. Distributed Generation as a demand side

resource must be evaluated on a consistent and comparable basis as other

resource options. I believe that EPE’s decision to unilaterally refuse to evaluate


DG as a feasible resource option does not meet the requirement or intent of the

IRP Rule."

EPE Compromise: EPE will consider modeling of customer-sited DG in

Strategist runs. Compromise alternative- model DG based on Lazard pricing for

solar DG, comparable to other supply-side resources.

Outcome: EPE to consider modeling of customer-sited DG in Strategist runs.

Compromise alternative-model DG based on Lazard pricing for solar DG,

comparable to other supply-side resources.

5. Resource life

"We are asking that EPE conduct its base analysis of resource options to

determine the most cost effective resource portfolio using the information from

Lazard’s Levelized Cost of Energy – V. 11.0 for all resource options that

Lazard’s contains information that will be modeled by Strategist. We are asking

that the Lazard’s information be utilized without modification for the base

analysis. We are specifically requesting that the Lazard’s values for facility life

be utilized in the base analysis."

EPE Compromise: EPE does not agree that modifying resource inputs from

public sources based on internal information and experience or other data is


inconsistent with the IRP Rule, but agrees on providing the rationale behind the

decision for each resource life.

Outcome: In progress; no resolution met.

6. Purchased Power Resources

"I am asking that EPE conduct all of its Strategist analyses with purchased power

as a resource option, beginning with 2019 through 2038 and define the purchase

price assumptions to be used. This is necessary to demonstrate that the preferred

resource portfolio identified by the Strategist analysis is the least cost resource

portfolio as required by the rule."

EPE Compromise:

Outcome: In progress; no resolution met.

G. Conclusion of Public Advisory Process

EPE made a significant effort to improve the Public Process in order to make it a more

inclusive and interactive process. By providing the Participants with additional features

such as meeting recordings, adding a facilitator, increasing the number of meetings and

public discussion time, providing Resource Input Templates, and including a written

request and response option, EPE made this its most accessible Public Process to date, and

is working to continuously improve its IRP process.


XI. CONCLUSION

The identified resource additions result in the optimal cost effective resource portfolio

and were identified through a robust and comprehensive Planning Process. The resulting

resource portfolio additions include a mix of solar, battery storage, and conventional gas

generation. The battery storage and conventional gas generation resources compliment

the solar resources, which are intermittent in nature. It is noted that the actual resource

additions in the future will be determined by results of competitive requests for proposals

and may differ based on future changes to forecasted loads, economic conditions,

technological advances, specific generation resource proposals, and environmental and

regulatory standards.


ATTACHMENT A: PUBLIC ADVISORY PROCESS

Attachment A-1: Original Public Advisory Meeting Schedule

Meeting Date Subject(1) 5/25/2017 Kick-off and Introduction

Explanation of IRP Process and GoalsResource Planning Process and OverviewPreliminary Listing of Resource Options to Consider

(2) 6/8/2017 Summary of IRP process and introduction to system(3) 7/6/2017 Operational Considerations/Requirements for Future Resources

Assessment of need for additional resourcesSystem Operations - Reliability, Import Limits and BalancingExisting Conventional Resources System generation retirement plan and processTransmission & Distribution Systems Overview and Projects

(4) 8/8/2017 Existing Renewable Resources and Distributed Generation (DG)Demand Response (DR) Programs and OptionsEnergy Efficiency (EE)Rate Considerations and Potential Impacts on Resource Planning DecisionsLoad ForecastLoad Forecast - Impacts from EE/DR and Rate Structure

(5) 9/7/2017 Conventional Capacity and Generation Option ConsiderationsDemand Side Resource OptionsRenewable Energy Options (Solar, Wind, Geothermal, Storage, DG)Operational Considerations for Intermittent Resources and BalancingRenewable Portfolio Standard ImpactsRenewable & Conventional Power Plant Siting and Environmental Considerations

(6) 10/5/2017 DEADLINE FOR OPTION SUBMITTAL FROM PUBLICResource Planning Base Case AssumptionsInitial Cost Estimates for Resource Planning OptionsModeling and risk assumptions and the cost & general attributes of potential additional resources

(7) 10/12/2017 Resource Planning Overview and Modeling for Cost of Potential Additional Resources(8) 11/16/2017 Preliminary Results with 2017 Load Forecast

Presentation of Resulting 20-year Expansion PlanDevelopment of the most cost-effective portfolio of resources for utility's IRP

(9)-(10) Jan 19, Feb 16 Informational Meetings or Discussions as Requested

(11) 4/30/2018 IRP Draft Presentation(12) 5/16/2018 Follow-up meeting to receive and respond to public feedback(13) 6/8/2018 Final IRP presentation showing new load forecast(14) 6/29/2018 Follow-up meeting to receive and respond to public feedback

7/15/2018 IRP Filing Date


Attachment A-2: Final Public Advisory Meeting Schedule

Meeting Date Subject(1) 5/25/2017 Kick-off and Introduction

Explanation of IRP Process and GoalsResource Planning Process and OverviewPreliminary Listing of Resource Options to Consider

(2) 6/8/2017 Summary of IRP process and introduction to system(3) 7/6/2017 Operational Considerations/Requirements for Future Resources

Assessment of need for additional resourcesSystem Operations - Reliability, Import Limits and BalancingExisting Conventional Resources System generation retirement plan and processTransmission & Distribution Systems Overview and Projects

(4) 8/8/2017 Existing Renewable Resources and Distributed Generation (DG)Demand Response (DR) Programs and OptionsEnergy Efficiency (EE)Load Forecast

(5) 9/7/2017 Conventional Capacity and Generation Option ConsiderationsDemand Side Resource OptionsRenewable Energy Options (Solar, Wind, Geothermal, Storage, DG)Operational Considerations for Intermittent Resources and BalancingRenewable Portfolio Standard ImpactsL&R TableStrategist IntroductionResource Input TemplateRenewable & Conventional Power Plant Siting and Environmental Considerations

(6) 9/22/2017 Presentation by PAG members Merrie Lee Soules and Don Kurtz: "Public Advisory Group Special Session on Analysis for 2018 IRP"

(7) 10/5/2017 Initial Resource Options Submittal from PAG Due for November RunRate Considerations and Potential Impacts on Resource Planning DecisionsResource Planning Base Case AssumptionsInitial Cost Estimates for Resource Planning OptionsModeling and risk assumptions and the cost & general attributes of potential additional resources

(8) 10/20/2017 Presentation by PAG Members Merrie Lee Soules, Phil Simpson, Allen Downs, and Steve Fischmann: Special Session on Resource Analysis for 2018 IRP

(9) 10/26/2017 Retirements, Cost Modeling Assumptions, and other topics of interest to PAG(10) 11/2/2017 SANTA FE - Overview on Public Advisory Process(11) 11/16/2017 Recap of IRP Process

Assumptions For Resource Options

Preliminary ResultsDevelopment of the most cost-effective portfolio of resources for utility's IRP

(12) 1/11/2018 PAG Presentations and Discussions as Requested

2/2/2018 Last Resource Input Submittals from PAG Due (13) 2/23/2018 PAG Presentations and Discussions as Requested(14) 7/19/2018 IRP Draft Presentation(15) 8/2/2018 Follow-up meeting to receive and respond to public feedback(16) 8/17/2018 Final IRP presentation showing new load forecast(17) 8/29/2018 Follow-up meeting to receive and respond to public feedback

9/17/2018 IRP Filing Date


Attachment A-3: Public Advisory Schedule with IRP Rule Requirements


Attachment A-4: Feedback Forms Summary

July 6, 2017 Feedback Form Summary

Consolidated feedback list by question: What do you hope to get out of the IRP Public Advisory Process? • A better understanding of EPE’s thinking on Renewable generation, Demand Peak control

and the future direction of the company. • Lots of information! You are doing a good job! Please see card for other questions. • Understanding rate case • Understanding how to plan for a reliable source plan with a higher use of solar, storage

changes for community solar • Understanding of why rate increase is needed? • Learn about transmission of power • Long term impact of growth need for power in your service area • Will EPE consider use of wind power and more solar power • A better understanding of the IRP process and my role as a member of the PAG • A good integrated plan that optimally provides reliability with pricing that helps our

community develop economically • I hope to build my knowledge and understanding of how EPE supplies reliable low cost

electricity to NM customers • A well reviewed (360o) least cost portfolio scenarios What topics on the meeting schedule are you most interested in? • From agenda

o Generation retirement process o Import limits and reliability o Demand response options


o Solar and storage options o Intermittent resource operational considerations o Modeling o 20-year expansion plan

• Other topics:

o Off-system purchases, solar, and other topics addressed in July 5, 2017 emails o Curious about how "solar" homes are going to be impacted differently from other homes

in the future? o Capital spend in context of changing resources o Retirement EPE Generation

o You tried to cover too much material which didn’t allow more time for questions

o Observation: Folks from EPE seem defensive.

o Solar, including community solar o Cost allocation by rate groups. Cost allocation and pricing allocation should be close in

practice. Currently 4CP allocates cost but rates are very different o Retirement justification o Loads and Resource table

o Just resource type


October 19, 2017 Feedback Form Summary

Q1: Has IRP content been addressed to depth that you wanted?

Too Much Too Little Just Right 2 3 3

Comments: • We're getting there • Initial presentations were superficial, EPE seems evasive, real consideration being

deferred to a later meeting or written questions. Written answers explained in numerical order instead of topical basis. Prior meetings rehashed which takes some air out of scheduled presentation and done in a fragmented way.

• Presentations too much to the point there is no time for questions/input from public.

With recent presentations, public input has been encouraged. Please continue this format.

• Sometimes one or two people take most of the time (attendees) • Too much irrelevant stuff. Too little satisfying requirements of IRP and PAG process.

Presentations are mostly PR documents. Load forecast was designed to impress but not elucidate. Didn't provide explanation of the numbers in L&R. EE didn't provide numbers on L&R.

• Too little for what I wanted. I wanted it to be free and open. Utility is trying to increase

its rate-base assets. I understand that this is how they best serve their stockholders, so it is an implicitly adversarial process with the ratepayers. They want to increase assets more than what is actually needed. Need to make sure Strategist is not run in a slanted way. EPE bonuses related to increased profits - conflict of interest.

• Learned a great deal from IRP meetings. Have been attending since they started. Not

keen on rate issue as grid reliability. As long as have a feedback opportunity, it serves a useful purpose.

Q2 If you are no longer attending IRP meetings, please explain why.

Comments:

Due to no answers on this question, EPE made follow up calls on February to those participants who dropped off in participation.

Q3 To date, has there been something you wanted to discuss that was not discussed?


Comments: • Energy storage in conjunction with solar. Challenges and possibilities? Electric vehicles • No. Speakers should identify themselves. PAG appear to be informed so level of

discourse should be higher. • How does EPE see the future of batteries for energy use in our area • More storage alternatives • Retirements are scheduled for October • No • No • How rates are calculated based on few peak hours. Most customers don't know that

65% of their rate is driven by peak to serve a couple of hours. Cost of refrigerated air should not be spread to all customers

• Demand Response needs to be evaluated as a resource not just a technique. Document

signed by 12 PAG members outlined what's required by statute for EE. If DR not treated as a resource, strong area of protest on IRP. EPE is under pressure to provide profit to investors. We recommend EPE hires consultant to look at DR options.

• Interested in reliability of grid and integrity of it. EPE grid is fragile compared to

others. Look at things that can be done to enhance integrity and reliability.

Q4 Are there topics you want to cover in more depth?

• Retirements. • Yes, most of them • Details of decreasing payments for solar customers. Why payments are lower. • Distribution expansion plan needs to be shared. How will EPE incorporate solar, wind,

batteries to facilitate cost reduction for customers. Willingness to reduce carbon footprint is needed. More attention to EE programs desired by customers.

• More on the solar discussion. How will it affect future billing? • More understanding environmental impacts


• Load forecast, resource options, modeling & analysis process, inputs, output, scenarios • Yes • No, I'm a consumer concerned about rates being raised. I'm concerned about private

solar panel ownership and solar panel benefits being reduced (surcharge) • Rates, results of all-source RFP, results of Burns & McDonnell study which should

include extension for 3, 5, 7, 10 years, and 440 filings for T&D construction to be reviewed in PAG process to assess which ones are needed.

• Sorely lacking is real time management for Demand Management. Real time info for

demand resource is needed.

Feedback Calls Summary February 2018 Is there a reason why you stopped attending PAG meetings?

Were the meetings what you expected them to be like?

What can we do to improve the Public Advisory Process next time around?

Scheduling Likes the content, but feels meeting is dominated by few PAG participants.

Break down into smaller groups for more personalized attention. Interest in DG. You're doing a great job.

Content not what PAG participant expected.

It is educational, but has problems with City inspectors.

Include Spanish translators (but I understand it may be costly)

Scheduling Very informative. Nothing critical on content and format. Wasn't clear if/how EPE would implement PAG's input.

Doesn't feel like input will be listened to.

No. People need to feel they're heard and addressed. The result seemed to be pre-determined.

People who know more than their one subject. It feels like EPE is just doing this because they have to.

Scheduling Yes, some of it is kind of over my head, but they're very informative. Some PAG participants are distracting.

Increase publicity of meetings

Content not what PAG participant expected.

No. Wanted to discuss tariff on solar panels.

Every department should be present to answer questions on everything.


Attachment A-5 Resource Input Template Example


ATTACHMENT A-6: Existing Units Operating Characteristics

TABLE A-6a

Unit Copper Fuel Costs Heat Rate Fixed and

Variable O&M Year $000 MMBtu/MWh $000 2018 1,012.88 14.26 1,385.33 2019 929.59 14.24 2,562.85 2020 1,152.43 14.34 1,516.62 2021 1,186.97 14.35 1,543.61 2022 1,129.00 14.44 1,527.23 2023 1,116.75 14.40 2,536.75 2024 1,454.68 14.77 1,992.21 2025 925.01 14.33 3,470.68 2026 1,511.57 14.47 2,053.28 2027 2,657.92 14.28 4,806.28 2028 1,961.85 14.21 4,165.32 2029 1,787.88 14.18 4,829.97 2030 2,112.83 14.23 4,380.56

TABLE A-6b

TABLE A-6c

Unit Newman 2 Fuel Costs Heat Rate Fixed and

Variable O&M Year $000 MMBtu/MWh $000 2018 2345.27 10.72 1493.48 2019 2162.07 10.70 3679.86 2020 2610.72 10.71 1562.22 2021 2702.66 10.71 1587.68 2022 2506.69 10.72 1608.49




TABLE A-6d


Variable O&M Year $000 MMBtu/MWh $000 2018 8,793.14 10.80 2,052.80 2019 8,952.61 10.72 2,115.69 2020 9,929.56 10.65 2,191.80 2021 8,591.36 10.62 3,366.99 2022 10,179.21 10.66 2,256.45 2023 7,633.94 11.03 2,522.87 2024 6,194.26 11.00 5,335.92 2025 8,048.12 11.04 2,608.79 2026 8,899.88 10.95 2,680.62

TABLE A-6e


Variable O&M Year $000 MMBtu/MWh $000 2018 37,406.77 9.16 6,138.79 2019 37,758.85 9.11 5,440.12 2020 34,474.98 9.10 7,466.85 2021 38,491.21 9.09 7,603.56 2022 38,483.76 9.10 5,677.21 2023 39,312.61 9.22 8,731.43 2024 31,486.93 9.24 9,295.32 2025 35,382.59 9.26 8,409.45 2026 38,287.18 9.26 6,081.16


TABLE A-6f


Variable O&M Year $000 MMBtu/MWh $000 2018 31528.01 8.37 6512.20 2019 30541.83 8.38 9155.73 2020 31406.27 8.40 6818.73 2021 32165.39 8.39 6937.38 2022 31216.38 8.39 10896.14 2023 31435.95 8.30 10916.71 2024 32443.07 8.30 8396.92 2025 33685.11 8.31 8561.34 2026 33091.14 8.32 9994.95 2027 35260.28 8.37 18177.75 2028 38831.31 8.38 15895.95 2029 39673.43 8.38 16203.21 2030 39569.68 8.38 22466.35 2031 39226.49 8.33 22394.46 2032 39610.16 8.32 16883.20 2033 40736.38 8.33 20440.06 2034 37452.38 8.32 18713.72 2035 38395.52 8.33 17424.55 2036 43993.16 8.35 25095.10 2037 44490.91 8.35 20368.90

TABLE A-6g

Unit Rio Grande 7 Fuel Costs Heat Rate Fixed and



TABLE A-6h


Variable O&M Year $000 MMBtu/MWh $000 2018 10,694.57 11.73 6,873.63 \2019 13,194.93 11.72 4,308.90 2020 13,736.40 11.68 4,414.16 2021 14,058.09 11.68 4,483.44 2022 14,354.78 11.69 4,557.58 2023 13,406.81 11.85 5,232.57 2024 11,476.66 11.87 9,100.75 2025 14,213.53 11.88 5,414.48 2026 14,993.43 11.85 5,519.29 2027 17,631.96 11.77 5,674.19 2028 19,070.53 11.75 5,773.61 2029 19,774.87 11.74 5,873.23 2030 15,884.36 11.72 11,463.74 2031 18,429.32 11.80 6,031.65 2032 18,192.04 11.83 6,143.75 2033 18,766.90 11.82 6,253.79

TABLE A-6i




TABLE A-6j

Unit Palo Verde 1 Fuel Costs Heat Rate Fixed and

Variable O&M Year $000 MMBtu/MWh $000 2018 14,393.95 10.21 29,387.79 2019 13,724.63 10.21 34,775.01 2020 15,433.57 10.21 34,140.09 2021 17,346.17 10.21 29,361.16 2022 15,014.63 10.21 34,808.89 2023 14,449.32 10.21 34,776.61 2024 15,218.28 10.21 29,904.77 2025 14,391.25 10.21 35,458.46 2026 14,622.78 10.21 34,798.66 2027 16,681.21 10.21 29,832.09 2028 15,658.05 10.21 36,104.24 2029 15,876.73 10.21 35,431.63 2030 17,688.69 10.21 30,368.51 2031 16,617.64 10.21 36,140.36 2032 16,971.34 10.21 35,454.69 2033 18,835.96 10.21 30,940.24 2034 17,700.08 10.21 36,824.36 2035 18,055.93 10.21 36,125.38 2036 20,127.58 10.21 30,863.48 2037 18,772.44 10.21 36,862.05


TABLE A-6k




TABLE A-6l




TABLE A-6m

Unit Montana 1 Fuel Costs Heat Rate Fixed and



TABLE A-6n




TABLE A-6o




TABLE A-6p




TABLE A-6q – Purchase Power

Purchase

Power

Year $/MWh

2018 46.39 2019 45.35 2020 47.04 2021 48.30 2022 49.60 2023 50.79 2024 52.39 2025 54.18 2026 56.16 2027 57.66 2028 59.23 2029 60.83 2030 62.46 2031 64.14 2032 65.87 2033 67.64 2034 69.47 2035 71.35 2036 73.27 2037 75.25

Note: The Purchase Power forecast shown in the table above represents the maximum annual market value. A market profile is used in conjunction with this forecast to shape the market on an hourly basis downward based on this peak value.


TABLE A-6r – Fuel Prices

Fuel Prices ($/MBTU)

Year GasInter(1) NewInter(2) GasIntra(3)

2018 2.68 2.61 2.74

2019 2.53 2.47 2.60

2020 2.55 2.49 2.66

2021 2.62 2.56 2.73

2022 2.70 2.64 2.80

2023 2.77 2.70 2.86

2024 2.85 2.78 2.95

2025 2.94 2.87 3.05

2026 3.05 2.97 3.15

2027 3.13 3.04 3.23

2028 3.19 3.10 3.29

2029 3.24 3.15 3.36

2030 3.30 3.21 3.42

2031 3.36 3.26 3.48

2032 3.42 3.32 3.55

2033 3.48 3.38 3.62

2034 3.54 3.44 3.68

2035 3.61 3.50 3.75

2036 3.67 3.56 3.82

2037 3.74 3.62 3.90 Note: (1) GasInter is interstate gas with service provided by EPNG. This gas is utilized at the Rio Grande Power

Plant.

(2) NewInter is also interstate gas provided by EPNG that is utilized at Montana and Newman Power Stations as well as the fuel source for generic resources.

(3) GasIntra is intrastate gas with service provided by Oneok and is utilized at Newman and Copper Power Stations.


Attachment B-1: 2018 Long Term Forecast



Attachment C-1: Transmission Facilities TABLE 1. Existing EPE Transmission Lines 115 kV and Above

EL PASO ELECTRIC COMPANY

Existing 115 kV and Above Internal Lines

RATING LENGTH STATE

From To kV Circuit MVA Normal

MVA Emerg

Miles From To

AMRAD ARTESIA 345 1 278 278 125.4 NM NM CALIENTE AMRAD 345 1 785 785 56.0 TX NM CALIENTE PICANTE 345 1 789 789 7.3 TX TX HIDALGO GREENLEE 345 1 763 763 60.0 NM AZ LUNA AFTON 345 1 930 989 57.3 NM NM LUNA DIABLO 345 1 939 939 84.2 NM NM LUNA HIDALGO 345 1 658 658 50.5 NM NM MACHO SPRINGS

LUNA 345 1 1033 1390 24.9 NM NM

MACHO SPRINGS

SPRINGERVILLE 345 1 728 728 201.4 NM AZ

NEWMAN ARROYO 345 1 700 700 30.3 TX NM NEWMAN AFTON 345 1 930 1028 29.9 TX NM PICANTE NEWMAN 345 1 787 787 16.2 TX TX WESTMESA ARROYO 345 1 681 681 201.8 NM NM AIRPORT TAP AIRPORT 115 1 115 153 2.7 NM NM AMRAD LARGO 115 1 113 113 7.7 NM NM ANTHONY ARROYO 115 1 105 105 24.4 NM NM ANTHONY BORDER STEEL 115 1 155 207 5.2 NM TX ANTHONY SALOPEK 115 1 155 207 17.3 NM NM ANTHONY NEWMAN 115 1 155 199 12.3 NM TX ANTHONY MONTOYA 115 1 155 207 10.2 NM TX ASCARATE TROWBRIDGE 115 1 171 171 0.5 TX TX ASCARATE COPPER 115 1 173 233 1.4 TX TX ASCARATE RIVERENA 115 1 173 233 1.4 TX AUSTIN MARLOW 115 1 209 209 1.2 TX TX BIGGS BLISS

INDUSTRIAL 115 1 173 233 2.4 TX TX

BLISS INDUSTRIAL

LIBERTY 115 1 173 233 2.2 TX TX

BUTTERFIELD FT. BLISS 115 1 120 120 1.9 TX TX CALIENTE DIAMOND

HEAD 115 1 173 233 6.0 TX TX

CALIENTE MPS 115 1 64 82 8.7 TX TX CALIENTE MPS 115 2 254 343 2.5 TX TX CALIENTE MPS 115 3 254 343 2.5 TX TX


CALIENTE VISTA 115 1 155 208 6.6 TX TX CHAPARRAL ORO GRANDE 115 1 120 120 35.4 NM NM COPPER PENDALE 115 1 127 165 5.0 TX TX COYOTE RGC_DEL CITY 115 1 19 19 10.8 TX TX CROMO RIO GRANDE 115 1 127 169 0.9 TX TX DIABLO RIO GRANDE 115 1 311 417 2.9 NM TX DIABLO RIO GRANDE 115 2 311 417 2.9 NM NM DIABLO ANAPRA 115 1 173 233 2.2

8 NM

DIAMOND HEAD LANE 115 1 173 233 2.6 TX TX DURAZNO ASCARATE 115 1 127 169 3.3 TX NM DYER SHEARMAN 115 1 127 169 9.6 TX TX DYER AUSTIN 115 1 173 233 2.1 TX TX FT. BLISS AUSTIN 115 1 120 120 1.8 TX TX GLOBAL REACH VISTA 115 1 313 313 3.0 TX TX HATCH JORNADA 115 1 39 39 33.4 NM NM HOLLOMAN LARGO 115 1 113 113 14.9 NM NM JORNADA ARROYO 115 1 74 74 4.9 NM NM LANE WRANGLER 115 1 155 207 1.0 TX TX LAS CRUCES ARROYO 115 1 155 207 4.1 NM NM LAS CRUCES SALOPEK 115 1 155 207 5.0 NM NM LEO EAST DYER 115 1 173 233 4.3 TX TX LEO EAST MILAGRO 115 1 173 233 3.8 TX TX LIBERTY GLOBAL REACH 115 1 173 233 2.6 TX TX MAR LARGO 115 1 23 23 11.4 NM NM MARLOW TROWBRIDGE 115 1 171 171 1.1 TX TX MESA AUSTIN 115 1 155 207 6.1 TX TX MESA RIO GRANDE 115 1 254 254 2.2 TX NM MILAGRO NEWMAN 115 1 173 233 6.3 TX TX MONTWOOD CALIENTE 115 1 173 233 5.0 TX TX MONTWOOD COYOTE 115 1 173 233 7.8 TX TX MPS COYOTE 115 1 235 369 2.9 TX TX MPS MONTWOOD 115 1 235 369 6.0 TX TX NEWMAN CHAPARRAL 115 1 127 169 2.9 TX NM NEWMAN BUTTERFIELD 115 1 127 169 16.7 TX TX NEWMAN SHEARMAN 115 1 127 169 7.3 TX TX NEWMAN PIPELINE 115 1 173 233 9.8 TX TX NEWMAN PICANTE 115 1 173 233 13.6 TX TX ORO GRANDE AMRAD 115 1 120 120 12.

3 NM NM

ORO GRANDE WHITE SANDS 115 1 69 69 22.8 NM NM PATRIOT NEWMAN 115 1 127 169 2.2 TX TX PATRIOT CROMO 115 1 127 169 17.7 TX TX PELICANO HORIZON 115 1 173 233 6.7 TX TX PELICANO MONTWOOD 115 1 173 233 3.8 TX TX


PENDALE LANE 115 1 173 233 1.5 TX TX PICANTE GLOBAL REACH 115 1 173 233 6.0 TX TX PICANTE BIGGS 115 1 173 233 2.3 TX TX PIPELINE BIGGS 115 1 127 169 13.6 TX TX RIO GRANDE RIPLEY 115 1 155 207 3.0 NM TX RIPLEY THORN 115 1 127 169 1.9 TX TX SALOPEK ARROYO 115 1 127 169 10.7 NM NM SANTA TERESA MONTOYA 115 1 173 233 7.4 NM TX SANTA TERESA DIABLO 115 1 158 212 8.9 NM NM SCOTSDALE VISTA 115 1 112 129 5.2 TX TX SOL LANE 115 1 127 169 2.1 TX TX SOL VISTA 115 1 173 233 2.0 TX TX SPARKS HORIZON 115 1 173 233 3.8 TX TX SUNSET NORTH DURAZNO 115 1 127 169 4.6 TX TX SUNSET NORTH RIO_GRAN 115 1 254 339 5.1 TX NM THORN MONTOYA 115 1 127 169 3.0 TX TX WRANGLER SPARKS 115 1 173 233 4.0 TX TX

-“Internal” refers to lines within EPE’s Balancing Area including lines connecting EPE to neighboring utilities, however, not including line segments partially owned by EPE external to EPE’s control area. -Some transmission lines were identified to be capacity limited by smaller jumpers connected at the substations. The line ratings reflected in the above table are based on line jumper upgrade assumptions.

- The ratings are generally based on conductor thermal capacities but may be derated due to sag limitations or other factors. - RGC_DC is Rio Grande Electric Cooperative, Dell City. - Emerg is short for Emergency


TABLE 2. Existing 115 kV EPE Substation Transformers

EL PASO ELECTRIC COMPANY

Existing 115 kV Load & Step-up Substation Transformers

RATING Normal Emergency State

MVA MVA AIRPORT 115/23.9 33.6 37.6 NM AMRAD 115/24.9 8.4 9.4 NM

ANTHONY #1 115/23.9 33.6 37.6 NM ANTHONY #2 115/23.9 56.0 62.7 NM ARROYO #1 115/23.9 33.6 37.6 NM ARROYO #2 115/23.9 33.6 37.6 NM

ASCARATE #4 115/69 112 125.4 TX ASCARATE #5 115/69 112 125.4 TX

AUSTIN NORTH #1 115/13.8 50.0 56.0 TX AUSTIN NORTH #2 115/13.8 56.0 62.7 TX

BORDER STEEL 115 #1 115/13.8 39.2 43.9 TX

BORDER STEEL 115 #1 115/13.8 39.2 43.9 TX BUTTERFIELD #1 115/13.8 30.0 33.6 TX BUTTERFIELD #2 115/13.8 30.0 33.6 TX

CALIENTE #3 115/13.8 33.6 37.6 TX CHAPARRAL #1 115/13.8 33.6 37.6 NM CHAPARRAL #2 115/13.8 33.6 37.6 NM

COPPER #1 115/13.8 30.0 33.6 TX COPPER GEN #2 13.8/115 84.0 94.1 TX

COYOTE #1 115/13.8 30.0 33.6 TX CROMO #1 115/13.8 30.0 33.6 TX CROMO #2 115/13.8 30.0 33.6 TX

DIAMOND HEAD #1 115/13.8 33.6 37.6 TX DURAZNO #1 115/13.8 33.6 37.6 TX

DYER #3 115/69 112 125.4 TX EMRLD #1 115/13.8 12.5 14.0 NM

FT. BLISS #1 115/13.2 27.5 30.8 TX FT. BLISS #2 115/13.2 28.0 31.4 TX

GLOBAL REACH #1 115/13.8 33.6 37.6 TX HATCH #1 115/24.9 30.0 33.6 NM

HORIZON #1 115/13.8 33.6 37.6 TX JORNADA #1 115/23.9 33.6 37.6 NM

LANE #1 115/69 100 112 TX LANE #2 115/13.8 30.0 33.6 TX


LAS CRUCES # 1 115/23.9 67.2 75.3 NM LAS CRUCES # 2 115/23.9 67.2 75.3 NM

LEO EAST #1 115/13.8 33.6 37.6 TX LEO EAST #2 115/13.8 33.6 37.6 TX

MAR #1 115/4.2 11.2 12.5 NM MESA # 1 115/13.8 30.0 33.6 TX MESA # 2 115/13.8 30.0 33.6 TX

MILAGRO #1 115/13.8 33.6 37.6 TX MILAGRO #2 115/13.8 33.6 37.6 TX MILAGRO #3 115/13.8 33.6 37.6 TX MONTOYA #1 115/24.9 33.6 37.6 TX MONTOYA #2 115/23.9 56.0 62.7 TX MONTOYA #3 115/23.9 56.0 62.7 TX

MONTWOOD #1 115/23.9 33.6 37.6 TX MONTWOOD #2 115/23.9 56.0 62.7 TX

MPS #1 13.8/115 140.0 156.8 TX MPS #2 13.8/115 140.0 156.8 TX MPS #3 13.8/115 140.0 156.8 TX MPS #4 13.8/115 140.0 156.8 TX

NEWMAN G1(T2) 13.8/115 125.4 140.5 TX NEWMAN G2 (T6) 13.8/115 125.4 140.5 TX NEWMAN G3 (T8) 13.8/115 125.4 140.5 TX

NEWMAN 4G1 (T11) 13.8/115 125.0 140.0 TX NEWMAN 4G2 (T9) 13.8/115 125.0 140.0 TX NEWMAN 4S1 (T13) 13.8/115 125.0 140.0 TX NEWMAN 5G1 (T15) 13.8/115 130.0 145.6 TX NEWMAN 5G2 (T16) 13.8/115 130.0 145.6 TX NEWMAN 5S1 (T14) 13.8/115 175.0 196 TX

PATRIOT #1 115/13.8 33.6 37.6 TX PELICANO #1 115/23.9 33.6 37.6 TX PELICANO #2 115/23.9 56.0 62.7 TX

PENDALE 115/13.8 33.6 37.6 TX PICACHO 115/24.9 56.0 62.7 NM REDEYE 115/13.8 14.0 15.7 NM

RIO GRANDE T1 115/69 112 125.4 TX RIO GRANDE T2 115/69 112 125.4 TX

RIO GRANDE G8 (T7) 17.5/115 168.0 188.2 NM RIO GRANDE G9 (T17) 13.8/115 132.0 147.8 NM

RIPLEY 115/13.8 33.6 37.6 TX SALOPEK #1 115/24.9 28.0 31.4 NM


SALOPEK #2 115/24.9 28.0 31.4 NM SALOPEK #3 115/24.9 28.0 31.4 NM

SANTA TERESA #1 115/23.9 30.0 33.6 NM SANTA TERESA #2 115/23.9 30.0 33.6 NM

SCOTSDALE #1 115/69 112 125.4 TX SHEARMAN #1 115/13.8 30.0 33.6 TX

SOL #1 115/13.8 33.6 37.6 TX SOL #2 115/13.8 30.0 33.6 TX

SPARKS #1 115/13.8 33.6 37.6 TX SPARKS #2 115/13.8 56.0 62.7 TX SPARKS #3 115/69 100 112 TX

SUNSET NORTH #1 115/13.8 33.6 37.6 TX SUNSET NORTH #2 115/13.8 33.6 37.6 TX SUNSET NORTH T3 115/69 70 78.4 TX

TALAVERA 115/23.9 16.5 18.5 NM THORN #1 115/13.8 33.6 37.6 TX THORN #2 115/13.8 33.6 37.6 TX

TRANSMOUNTAIN

115/23.9 22.4 25.1 TX VISTA #1 115/13.8 30.0 33.6 TX VISTA #2 115/13.8 30.0 33.6 TX

WHITE SANDS #1 115/13.8 30.0 33.6 NM WRANGLER #1 115/13.8 50.0 56.0 TX

TABLE 3. EPE 345/115 kV Autotransformers

Existing Auto Transformers

115 kV and Above

Voltage

kV

RATING State Normal Emergency

MVA MVA

AMRAD T1 345/115 290 333 NM ARROYO T1 345/115 224 258 NM ARROYO T5 345/115 224 258 NM ARROYO T6 345/115 224 258 NM

ARROYO T3 345/345 400 460 NM CALIENTE T1 345/115 224 258 TX CALIENTE T2 345/115 224 258 TX DIABLO T1 345/115 224 258 NM DIABLO T2 345/115 224 258 NM DIABLO T3 345/115 224 258 NM NEWMAN T1 345/115 230 265 TX PICANTE T1 345/115 224 258 TX


TABLE 4. EPE External Line Segments

EPE External Transmission Segments (Arizona)

EPE share of

TTC (MW)

EPE share of

ATC (MW)

TTC of PV East

Path (MW)

Path Description Point of Receipt

Point of Delivery

Palo Verde Westwing 500 *

TTC-439

Two line segment in which 500 kV kV (1) has

Westwing Palo Verde 500 TTC-440- 500 kV kV (2) ** CST an 18.7% ownership interest

Palo Verde Jojoba 500 kV

555 TTC-203-

One line segment in which EE

500 kV (3) CST has Jojoba 500 Palo Verde 500

kV kV (4) 555 TTC-CST an 18.7% ownership interest

Jojoba 500 Kyrene 500 kV *

TTC-203-

One line segment in which EE kV (3) CST has

Kyrene 500 Jojoba 500 kV kV (4) ** TTC-CST an 18.7% ownership interest

Note: EPE's share of TTC on the Palo Verde East System is 1118 MW (1) EPE has retained 439 MW (AREF Set Aside) ATC for native load uses (2) EPE has retained 400 MW (AREF Set Aside) ATC for use by TEP (3) EPE has retained 203 MW (AREF Set Aside) ATC for native load uses (4) At the present time, there are no Committed Uses on this segment * TTC for PV East System ** TTC for PV East System in east to west

direction CST - Common Segment Transactions


TABLE 5. Under-Construction EPE Transmission Facilities

Under Construction /

Status *

Transmission Facility

State

Under Construction Lane - Pendale 115 kV Line Reconductor TX

Under Construction Rio Bosque Substation 69 kV Capacitor Bank TX

Under Construction Sunset N-Durazno Transmission line TX

Under Construction Pendale - Copper 16900 Line Rebuild TX

Under Construction Sunset N-Durazno 115KV Transmission Line Upgrade

TX

Planned

Hidalgo Substation Reactor Substation Reactor Replacement

NM

Planned Ft. Bliss 30 MVAR Cap Addition 115KV BUS TX

* Refers to the project status during the development of this filing.



Attachment D- 1: Lazard’s For the 2018 IRP Process EPE utilized Lazard's Levelized Cost of Energy Analysis –Version

11.0 which can be found at the link below:

https://www.lazard.com/perspective/levelized-cost-of-energy-2017/

For the 2018 IRP Process EPE utilized Lazard's Levelized Cost of Storage Analysis –Version 3.0

which can be found at the link below:

https://www.lazard.com/perspective/levelized-cost-of-storage-2017/

https://www.lazard.com/perspective/levelized-cost-of-energy-2017/

https://www.lazard.com/perspective/levelized-cost-of-storage-2017/


ATTACHMENT E- 1 : Expansion Plan Results – Base Case and Sensitivities

TABLE E-01a Base Case


TABLE E-01b Low Load Sensitivity


TABLE E-01c High Load Sensitivity


TABLE E-01d Low Natural Gas Price Sensitivity


TABLE E-01e

High Natural Gas Price Sensitivity


TABLE E-01f $8 CO2 Tax Price Sensitivity


TABLE E-01g $20 CO2 Tax Price Sensitivity


TABLE E-01h $40 CO2 Tax Price Sensitivity


TABLE E-01i No Combined Cycle Sensitivity

El Paso Electric Company A-1 2018 Integrated Resource Plan

Documents

El Paso Electric Company Integrated Resource Plan For the ......Paso Electric Company's (“EPE” or the “Company”) most recently filed periodic reports and in other filings made